3.1 RIG SITE - Dimensions and Safety - Dimensions Rig site dimensions depend on different factors: - Place (village, mountain, desert, forest) - Local laws and regulations - Rig type - Drilling programme and risks (H2S, HP/HT, etc.) - Water supply (water well, river, trucks with pits, etc.) - Operating and economical factors - Safety For the safety of the people, the rig and the environment, some aspects must be considered in the project phase: - rig must be positioned following the main wind direction; above all if H2S is foreseen; - Emergency escape roads must be prepared in different direction; - Different access way must be prepared in case the main road is inaccessible (i.e. Blowout); - Observe minimum distance between equipments according to laws and regulations.

- Example of Hazardous area classification - Plans Minimum distances according to Italian and European laws.

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- Lay-out Examples - Minimum Lay Out for G125 Rig

- Example of Massarenti 7000 Lay Out

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- Example of 3 Well Cluster for 2000 HP Rig

- Example of Lay Out for 3000 HP Rig

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- Civil Works on Location - Example of Civil Works On Location

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3.2 CELLAR DIMENSIONS

- Cellar breadth Cellar breadth is usually decided with the Rig Contractor, considering well head, BOP and substructure. The cellar is usually cased in concrete to avoid collapse with the weight of the rig.

4.1 FUNCTION The substructure has the function of supporting the drawworks, rotary table, stands of DP and derrick. The top side is generally called the rig floor. Substructure are made following API STD 4E or 4F regulations. There is usually a plate mounted on the substructure identifying its main characteristics.

4.3 TYPES AND CHARACTERISTICS - Substructure Types Land rigs are made for frequent Rig Up, moving and Rig Down. This is the main reason why different substructure types have been developed. Two main types - Type Box on Box - Type: High Floor Substructure - Type Box on Box Different modules or boxes are positioned to raise the rig floor. The numbers of boxes depends on the height required to install the wellhead and BOP stack.

- Type: High Floor Substructure These have been developed to accommodate higher BOP stacks and wellheads. Although each builder has their own model, they all have the following characteristics: Enables the drawworks and derrick to be rigged up at ground level, eliminating the need for big cranes; Uses the rig's drawworks to raise the floor and derrick (some models use hydraulic pistons).

- Derricks Derricks and Masts consist of a steel framework with a square or rectangular cross-section. Their purpose is to support the hoisting equipment and rack the tubulars while tripping. The number of joints in a stand (single-double-triple) that the rig can pull is dependent on the height of the derrick. - Manufacturer Specifications Derricks are manufactured in accordance with API 4F or related ISO (International Organization for Standardization) 13626 draft. This specifications covers the design, manufacture, and use of derricks, portable masts, crown block assemblies and substructures.

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- Nameplate Information Derricks built within API/ISO specs must have a specification nameplate attached in a visible place containing the following information:
a. MANUFACTURER’S NAME.

5.2 TYPES AND CHARACTERISTICS There are 3 different types of derricks: - DERRICK - MAST - RAM RIG - DERRICK Pyramidal steel framework with square or rectangular cross section assembled as fixed structure. - API Definition A semipermanent structure of square or rectangular cross-section having members that are latticed or trussed on all four sides. This unit must be assembled in the vertical or operation position, as it includes no erection mechanism. It may or may not be guyed.

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- Derrick dimensions Table 1 - Derrick Sizes and General Dimensions

A - The vertical distance from the top of the base plate to the bottom of the Crown Block support Beam. B - The distance between heel to heel of adjacent legs. C - The window opening measured in the clear and parallel to the center line of the derrick side from top of base plate. D - The smallest clear dimension at the top of the derrick that would restrict passage of crown block. E - The clearance between the horizontal header of the gin pole and the top of the crown support beam.

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Derrick Types Derrick are normally used on Offshore rigs and can be divided into categories: - Stationary Derrick Derrick used on offshore fixed structures - Dynamic Derrick Heavyweight derrick used on floating rigs subjected to marine stress.

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Installation on offshore floating unit

Dynamic Derrick mounted on DS SAIPEM 10000

- MAST A Mast is a steel framework with square or rectangular cross-section comprised of multiple sections assembled together. Mast are normally used on land rigs; they are rarely used on offshore rigs. Most masts have one side open (window side), while others have both the front and rear side open (full view). Generally masts are assembled on the ground in horizontal position and are raised using the drawworks. Some masts use telescopic sections and are assembled in vertical (boot strap). - API Definition 3.16 mast: A structural tower comprised of one or more sections assembled in a horizontal position near the ground and then raised to the operating position. If the unit contains two or more sections, it may be telescoped or unfolded during the erection procedure.

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Mast Types There are 2 different types of masts for land drilling and service rigs: - STATIONARY BASE - WITH GUY LINES
Stationary Base

With Guy Lines

- Pyramid Mast sizes table

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Example 1

Example 2

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- RAM RIG

The RAM RIG is a new concept used to hoist the drill string. The Drawwork and the drilling line are replaced with a system of hydraulic pistons and rams. Ram rigs can be used with singles or stands, depending on the height of the derrick. They have only recently been developed and are not yet classified within API/ISO Specs

Case 1: Suspended load The load on the support is equal to the weight being hung.

Case 2a : Static Load Drilling load is at rest, hoisted by the Drawworks over a single sheave on the Crown Block The load on the drawworks is equal to the weight being hung from the crown sheave. The crown supports both the drilling load and drawworks tension, so the force supported is double the weight being hung.

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Case 2b : Dynamic Load Drilling load is in motion, hoisted by the Drawworks over the single sheave on the Crown Block The load on the drawworks is equal to the weight being hung from crown sheave PLUS frictions. The crown block supports both the drilling load and the drawworks tension PLUS frictions, so the force supported in more than the weight being hung.

Case 3: Drilling load is in motion Drilling load is in motion, hoisted by the Drawworks through a series of sheaves on the Crown and Travelling Blocks The load supported by the Crown Block is the sum of the load supported by each of the lines. In this example with 3 lines, the load supported by Crown block is 1500 kg

The load supported by the Drawworks is the drilling load divided by the number of lines on the traveling block. In this example the force required by the drawworks to hoist a weight of 1000 kg is reduced by by using a travelling block with one sheave. The series of sheaves in Crown-Travelling Blocks system reduces the load necessary to hoist a weight.

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- Series of sheaves and Lines - Load Supported by the Drawworks The series of sheaves in Crown-Travelling Blocks system reduces the load necessary to hoist a weight. The load supported by the drawworks is related to the number of lines installed on the Travelling Block.

- Definition of Gross Nominal Capacity - Gross Nominal Capacity Gross nominal capacity is defined as the MAXIMUM STATIC LOAD with a stated number of drilling lines. API regulation takes in consideration only the capability for hoisting the drill string. - Calculation of GNC for Mast In a MAST the maximum load to the crown block(Gross Nominal Capacity) is calculated as follows:

Example of Load distribution on a Mast - Calculation of GNC for Derrick In a DERRICK the maximum load applied at the crown block (Gross Nominal Capacity) is equally divided on its 4 legs and its calculated as follows:

The Drawworks is one of most important equipment on drilling rig. The unit supplies the hoisting power, the drawworks spools the drilling line as pipe is run into and pulled out from the well. The drilling line spools out under gravity and is reeled in by an electrical or diesel engine.

Schematic Draw

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- Manufacture specifications The Drawworks is built in according to specifications in API 7K or related ISO (International Organization for Standardization) 14693.

Drawworks

6.2 TYPES AND CHARACTERISTICS Depending on the engines on the rig, the drawworks can be either: - MECHANICAL - ELECTRICAL

- MECHANICAL Diesel engines are directly connected (compounded) to the drawwork by chain. This system is still in use for small Drilling Rigs (under 1500 HP), but is no longer used on medium-Hi powered rigs( 1500 & 3000 HP).

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- ELECTRICAL Electrical system are normally used today on land rigs and is the only system in use on offshore rigs. The drawworks are generally connected to 1000 HP D.C. engines, although A.C. engines are now being used as well.

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- Connection Drawworks-Engines The connection between the drawworks and the engines can be either: - CHAIN DRIVEN - GEAR DRIVEN ELECTRIC TYPE (Chain-Driven)

a - Main Drum - Main Drum Diameter The diameter of the main drum is a function of the diameter of the drilling line being used. It is preferable to have the drum as large as possible to reduce the number of wraps and the bending of the cable. - Drum Length The length of the drum is a function of the distance between Crown block and Drawworks. - Fleet Angle To reduce the wear on the drilling line, it is good practice to keep the angle alpha under 2 degrees. (see pictures)

b - Catheads - Spinning line and Breakout Cathead Catheads are winches with pneumatic clutch and are mounted on the extremity of the secondary drum of the drawworks. The make up cathead is located beside the driller's console and the break-out cathead is located on the opposite side of the driller's console. The catheads apply the pulling force on the hand tongs connections. - Model 16 Spinning line Cathead - Model 16 Breakout Cathead

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- Employment scheme For safety reasons and convenience their employment comes supplanted from the dedicated equipments.

c - Stationary Brake

- Band Brake - Disk Brake - Regenerative Brake System

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- Band Brake - Description (parts) - BRAKE HANDLE - LEFT BAND - RIGHT BAND - BALANCE BAR - Braking action Braking action is activated by pushing the Brake handle down towards the floor. Through a strength multiplier system, the braking force is transmitted on the balance bar, then to the brake bands, and finally to the two drums on either side of main drum. Heat produced by the braking action is dissipated through the circulating water cooling system.

- Disk Brake Depending of the size the drawworks, there are 2 to 4 hydraulically-actuated calipers. In addition to these main calipers, each disc brake system has 2 dedicated calipers (normally closed) that are used as the emergency and parking brake. These calipers are actuated by an independent hydraulic system. Disk brakes can be mounted on Drawworks that was originally equipped with band brake.

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- Advantages The advantages are: - Greater braking capability - Emergency braking system - Possibility of Remote control - Significant noise reduction during drilling - Use Disk Brake is a development of the band brake, due to the necessity to handle heavier loads

- Performance Comparison diagram of 3 brake combinations

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- Regenerative Brake System - New generation of drawworks The newest generation of drawworks (4000-5000 HP), mounted on ultradeep offshore rigs, have a direct drive transmission system, permanently connecting the drawworks to the motors. When the travelling block descends in the derrick, the motors turns in the opposite direction, producing an opposite current and hence a braking action. - NOTE: This braking system, is not able to hold, when the motors are rest, hence the need for emergency and parking the disk brake system. Regenerative Brake System

d - Auxiliary brake / dynamic brake The function of the auxiliary brake is to assist the main braking system during rapid descent of the blocks with heavy string weights. The auxiliary brake prevents the overheating and premature wear of main brakes. Types: - Hydrodynamic Brake - Elettromagnetic Brake

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- Hydrodynamic Brake That system is still in use on small drawworks. However, on medium-Hi powered drawworks, this system has been replaced by the Electromagnetic brake.

- Description The Hydrodynamic brake consisting of two box with a rotor pressed onto the main drive shaft and two stators. When the main shaft rotates the rotor drags water against the two stators, producing a braking action. Braking capability can be regulated by increasing or decreasing the water levels in the "Hydraulic Brake box".

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- Hydrodynamic Brake The electromagnetic brake consists of a stator with coil, two magnetic poles and a rotor pressed onto the main drive shaft. When the driller activates the brake control, a magnetic field is produced by 4 electromagnetic coils mounted concentrically inside the drum. By varying the amount of current to these stationery coils, the driller can control the amount of braking torque applied to the rotating drum.

- "Baylor" brakes The use of electromagnetic brake began with diesel-electric rigs. Almost all drawworks today are equipped with "Baylor" brakes. Baylor Brakes are manufactured in 5 standard sizes for nominal drilling depths up to 30.000feet.

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- Braking force The diagram shows the values of braking force as a function of rpm of the drawworks shaft. Notice how the electromagnetic brake is also effective at low speeds.

- Crown block definition The Crown Block is a fixed set of pulleys (called sheaves) located at the top of the derrick or mast, over which the drilling line is threaded. The companion blocks to these pulleys are the travelling blocks. By using two sets of blocks in this fashion, great mechanical advantage is gained, enabling the use of relatively small drilling line to hoist loads many times heavier than the cable could support as a single strand. - Sheave characteristics The number of sheaves on the two Blocks (Crown and Travelling ) can range from 5 to 8 and is a function of the Hoisting system capability. The rating of the Crown Block must be higher than the Travelling Blocks. The diameter and the groove of sheaves depends on the diameter of drilling line in use. This values are established by the builder based the recommendations of API RP 9B. The ratio of sheaves diameter to drilling line diameter should be between 30-40. Crown Block

- API specifications The Crown Block, Travelling Block and the Hook are built in accordance with API specifications 8A or 8C.

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7.2 TYPES AND CHARACTERISTICS - Groove size The groove on the sheaves must be same size as the diameter of drilling line used to provide the right support. (Fig. 77) A groove to wide will flatten the drilling line, while a groove to narrow will cause high friction and excessive wear on the drilling line.

Groove (Fig. 77) - Typical Derrick Crown Block

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7.3 INSPECTIONS

- Periodic inspections The Crown Block, as with all Hoisting equipment, must have periodic inspections according to the builder's recommendations and API RP 8B. ENI procedures stipulate that the Crown Block be certified every 5 years, in addition to the mandatory periodic inspections. - Frequency of Periodic Inspections The frequency of periodic inspections is: - Daily - Monthly - Semi-annual - Annual - Five-year - Table: Periodic Inspection and Maintenance Categories and Frequencies

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- API Recommended Practice 8B CATEGORIES Category I Observation of equipment during operation for indications of inadequate performance. Category II Category I inspection, plus further inspection for corrosion; deformation; loose or missing components; deterioration; proper lubrication; visible external cracks; and adjustment. Category III Category II inspection, plus further inspection which should include NDE of exposed critical areas and may involve some disassembly to access specific components and identify wear that exceeds the manufacturer's allowable tolerances. Category IV Category III inspection, plus further inspection where the equipment is disassembled to the extent necessary to conduct NDE of all primary load carrying components as defined by the manufacturer. FREQUENCY The owner or user of the equipment should develop his own schedule of inspections based on experience, manufacturer's recommendations, and consideration of one or more of the following factors: - testing; - environment; - repairs; - load cycles; - regulatory requirements; - remanufacture - operating time; As an alternative the owner or user may use Table 1.

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- Example of Dimensional Inspection a. scheme b. Measures and Methods The Drilling Contractors must have a sheave gauge to carry out the checks and measurements to evaluate wears.

- Example of NDT Inspection

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08. TRAVELLING BLOCK INDEX 8.1 FUNCTION 8.2 TYPES AND CHARACTERISTICS 8.3 INSPECTIONS 8.1 FUNCTION The Travelling Block is a set of sheaves (pulleys) that move up and down in the derrick. The drilling line is threaded (reeved) over the sheaves on the crown and through the sheaves in the travelling block. This provides a great mechanical advantage to the drilling line, enabling it to lift heavy loads of pipe and casing.

The number of the pulleys used on the two Blocks can vary from 5 to 8, providing a variable capacity to the Hoisting system.

Travelling Block - Manufacture Specifications The diameter and groove of the pulleys depends on the dimensions of the drilling line to be used. These values are determinated by manufacturer in accordance with API RP 9B. The ratio of sheave diameter to drilling line should be between 30-40:1. The travelling blocks is built in accordance with API Spec. 8A and 8C. The reference standards adopted by ENI is: ISO 13535

8.2 TYPES AND CHARACTERISTICS \ - Groove size The size of the groove should be the same as the diameter of drilling line in order to provide the proper support. A pulley groove too large could flatten the drilling line and a groove too small can cause high friction and excessive wear on the drilling line.

- API Recommended Practice 8B - CATEGORIES Category I Observation of equipment during operation for indications of inadequate performance. Category II Category I inspection, plus further inspection for corrosion; deformation; loose or missing components; deterioration; proper lubrication; visible external cracks; and adjustment. Category III Category II inspection, plus further inspection which should include NDE of exposed critical areas and may involve some disassembly to access specific components and identify wear that exceeds the manufacturer's allowable tolerances. Category IV Category III inspection, plus further inspection where the equipment is disassembled to the extent necessary to conduct NDE of all primary load carrying components as defined by the manufacturer. - FREQUENCY The owner or user of the equipment should develop his own schedule of inspections based on experience, manufacturer's recommendations, and consideration of one or more of the following factors: - environment; - testing; - repairs; - load cycles; - remanufacture. - regulatory requirements; - operating time; As an alternative the owner or user may use Table 1. Eni Corporate University 72

- Manufacture Specifications The Hook blocks is built in accordance with API Spec. 8A or 8C. The reference standards adopted by ENI is: ISO13534 / 13535"

Hook

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9.2 TYPES AND CHARACTERISTICS Standard Hook

- Structure and components The hook is composed of 2 parts: upper and lower. The upper part has a spring that absorbs the bouncing action when tripping pipe. The lower part allow the hook to rotate facilitate different operations. It can also be locked to avoid undesired rotation, such as when tripping.

9.3 INSPECTIONS - Periodic inspections The Hook, as with all Hoisting equipment, must be inspected according to the manufacturer's recommendations and API RP 8B. ENI procedures stipulate that the hook must be re-certified every 5 years, in addition to the required periodic inspections.

- API Recommended Practice 8B - CATEGORY Category I Observation of equipment during operation for indications of inadequate performance. Category II Category I inspection, plus further inspection for corrosion; deformation; loose or missing components; deterioration; proper lubrication; visible external cracks; and adjustment. Category III Category II inspection, plus further inspection which should include NDE of exposed critical areas and may involve some disassembly to access specific components and identify wear that exceeds the manufacturer's allowable tolerances. Category IV Category III inspection, plus further inspection where the equipment is disassembled to the extent necessary to conduct NDE of all primary load carrying components as defined by the manufacturer. - FREQUENCY The owner or user of the equipment should develop his own schedule of inspections based on experience, manufacturer's recommendations, and consideration of one or more of the following factors: - environment; - testing; - load cycles; - repairs; - regulatory requirements; - remanufacture. - operating time; As an alternative the owner or user may use Table 1.

- Wire rope Wire rope is an intricate network of close tolerance, precision made steel wires, much on the order of a machine, where each part has a job to do. Wire Rope is composed three parts: - the CORE, - the STRAND and - the WIRE. API 9A defines drilling lines with abbreviations in function of: Type of core (Steel or fiber) Number of strands Number of wires per strand

Wire rope - CORE The center wire of the drilling line can be one of two types: FIBER CORE: Either of natural fiber such as sisal or man-made fiber such as polypropylene. WIRE ROPE CORE: Steel wire

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- LAY: Direction The first element in describing lay is the DIRECTION the strands lay in the rope Right or Left. When you look along the rope, strands of a Right Lay rope spiral to the right. Left Lay spirals to the left. The second element describing lay is the relationship between the direction the strands lay in the rope and the direction the wires lay in the strands. In regular Lay, wires are laid opposite the direction the strands lay in the rope. In appearance, the wires in Regular Lay are parallel to the axis of the rope. In Lang Lay, wires are laid the same direction as the strands lay in the rope and the wires appear to cross the rope axis at an angle. a) RIGHT REGULAR LAY b) LEFT REGULAR LAY c) RIGHT LANG LAY d) LEFT LANG LAY e) RIGHT ALTERNATE LAY

LAY

- LAY: Length of the Rope Axis The third element in describing lay is that one rope lay is length the rope axis which one strand uses to make one complete helix around the core. For API 9A regulations one rope lay is usually 7 to 8 times the nominal diameter.

Drilling line nominal diameter measurement

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- Nomenclature Example 1" x 5000' 6 x 19 S PFR RRL IPS IWRC 1" 5000' 6' 19 S PRF RRL IPS = Diameter of Line = Length of Line = Number of Strands per Line = Number of Wires per Strand = Seale Pattern; Seale All layers contain the same number of

- Total length of drilling line Depending on the height of the derrick and the number of lines to be strung, the total length of drilling line can vary from 650 to 1750 feet. - Heavy wear Heavy wear occurs in 3 localized areas: 1. Where the drilling line makes contact with the crown block and the travelling block sheaves 2. The position of the drilling line on the sheaves when the slips are set and pulled 1. 3. The position on the drum where each wrap of the drilling line crosses over the layers below

10.4 DEADLINE ANCHOR - Deadline Anchor The deadline anchor provides for the attachment of the Martin Decker weight indicator and can be either on the drilling floor or underneath the floor in the substructure. - Anchor Size The anchor must be least 15 times the diameter of the drilling line.

Cable tool-line Stand line Rotary drilling line Hoisting service other than rotary drilling Mast raising and lowering line Rotary drilling line when setting casing Pulling on stuck pipe and similar infrequent operations

10.6 DRILLING LINE WEAR - Drilling line Wear In working the line, heavy wear occurs a few localized sections: where the rope makes contact with the travelling block sheaves, the crown block sheaves and the drum. - Slipping and cutting drilling line For this reason there is the procedure of SLIPPING AND CUTTING DRILLING LINE Cut is done every 2 - 4 slipping. Slipping new rope through the system shifts the drilling line through these critical wear areas and distributes the wear more uniformly along the length of the rope Extreme positions in the operations of run and pool out of hole SLIP AND CUT TON-MILES CALCULATION SLIP AND CUT TON MILES CALCULATIONS AS PER API RP9B - Work Done During Round-Trip The only complicated part of a cut-off procedure is the determination of how much work has been done by the wire rope. Methods such as counting the number of wells drilled or keeping track of days between cuts are not accurate because the loads change with the depth and with different drilling conditions. For an accurate record of the amount of work done by a drilling line, it's necessary to calculate the weight being lifted and the distance it is raised and lowered. In engineering terms, work is measured in foot-pounds. On a drilling rig the loads and distance are so great that we use "ton-miles". One Ton-mile equals 10,560,000 footpounds.

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- Work Done During Reaming With reaming after drilling the stand Without reaming after drilling the stand

- Work Done During Drilling with Top Drive (with stands)

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- Work Done During CSG The ton-miles of work done in setting casing would be one-half the ton-miles done in making a round trip if the weight of the casing were the same as the weight of the drill pipe.

- CHARTS EXAMPLE Charts example from which it's possible deduce the unitary weigh of the various tubular of BHA (Bottom Hole Assembly)

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a) Effective Weight of Pipe in Drilling Fluid

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b) Effective Weight of Drill Collars in Drilling Fluid

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SLIP AND CUT

- Slip and Cut the drilling line Every contractor follows a programme, depending on the kind of rig, wire rope, drawwork, etc, to calculate when to slip and cut the drilling line.

1. Do not accumulate more than 3700 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3700 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T - M since last cut 25.0). 3. This program is based upon a goal of 25.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC tool Pusher's manual

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10.7 DRUM - Drum size Total length of drilling line depends on the drum size. Sometimes it's enough to put a new standard drum with the new drilling line. For some rigs the new drilling line must be passed in the dedicated Rig drum with different dimensions.

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- Service Life Relationship Between Rotary-Line Initial Length and Service Life

11.1 TYPES OF POWER GENERATORS - FOR MECHANICAL RIGS - FOR ELECTRIC RIGS FOR MECHANICAL RIGS - Diesel engines Power for mechanical rigs is developed by diesel engines connected directly to the load (drawworks, mud pumps, etc). Power for the lighting system and small loads (like mud agitators, shakers, etc) comes from a dedicated electric generator. - Example of a typical rig In this example of a typical rig, 3 diesel engines drive the drawworks, pumps and rotary table through a gear transmission system. Typical rig

- Connection Engine - Drive shaft There are 2 devices used on a mechanical system to connect the engine and the drive shaft: - HYDRAULIC COUPLER - TORQUE CONVERTER Hydraulic Coupler Torque Converter

The devices are beneficial since they can absorb strains on the system such as those present when starting the engines. The Hydraulic coupler provides a smooth transfer of power by absorbing mechanical strains. Eni Corporate University 107

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The Torque converter, in addition to functioning as a hydraulic coupler, also operates as a gear shifter by regulating torque variations.

- Hydraulic Coupler Oil position when the hydraulic coupling has stopped Oil position when the hydraulic coupling is on starting phase Oil position when the hydraulic coupling has assumed a constant speed

- Torque Converter Fluid movement inside the torque converter

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Direct connections between motors and torque converter

Indirect connections between motors and torque converter

FOR ELECTRIC RIGS ELECTRIC POWER GENERATION - DC electric generator DC-DC Drives Ward-Leonard DC-DC drives on drilling rigs usually consist of a diesel engine coupled to a DC generator operating at a constant speed. The output of the generator is controlled by varying its shunt field excitation. These systems are dedicated to a single purpose. Any load changes caused by drilling activity are supplied immediately by the motor. The engine and generator rarely interfere with other rig functions. The engine and DC generator must have adequate capacity to supply full load and accelerating current under all load conditions over the operating speed range. - AC electric generator AC-DC drives - Silicon Controlled Rectifier (SCR) Ward Leonard DC-DC drives have been replaced lately with a Silicon Controlled Rectifier (SCR) systems. In these systems, AC generator power is converted to DC voltage eliminating the need for a dedicated generator for each drilling function. AC loads do not need dedicated generators since they are connected directly to the AC generator.

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- Power distribution examples Typical electrical one-line diagram of a land rig system

Offshore Rig - Power distribution

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-

Jack Up Power Distribution.

AC-AC drives The AC-AC system is the latest generation of power distribution. Generators and all loads (drawwork, pumps, etc) are AC. - Variable Frequency Drives Because N= f x 120 / P where: f = voltage frequency Hz P = number of machine poles N = shaft speed , rpm Variable Frequency Drives can convert the fixed voltage and frequency into variable voltage and frequency to power AC motors at variable speed. - Benefits of an AC system AC motors do not have brushes and therefore create no sparks (beneficial in hazardous areas). Less maintenance. Can reverse drawworks and rotary table by reversing phase sequence.

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Lighter and smaller (GE 752 DC weights 7200 lbs and GEB-AC 6300 lbs).

- Rigs connected to Power Distribution Net
Power supply at MT for civil and industrial users is 20.000 Volts. Transformers reduce tension to 600 V. Variable Frequency drivers change frequency from 50Hz to 60Hz if on the rig are installed AC loads manufactured as per American standards. SCR system supplies DC power to DC loads. Emergency generator automatically starts in case of Main power supply interruptions

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Rig connected to Power Supply

Rig connected to Power Supply with Variable Frequency Drives

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- How much electrical power does a rig need ? Classification of Electric Drilling Rigs

12.1 DIESEL ENGINES - Characteristics Diesel engines are characterized by their low speed of operation, limited speed range, relatively low maintenance and general availability. The selection of diesel engines to drive electric generators is obvious because their similar operating speeds allow direct coupling, the torque and horsepower of both are compatible, and control of engine-generator speeds allows relatively easy control of generator output power. Fuel is usually diesel but also methane could be used. Diesel Engines

- Caterpillar Engines Caterpillar engines are the most commonly used engines because of their reliable operation. Some rigs today still use D-399 TA engines, even though they are no longer being produced.

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Performance

Dimension Data

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12.2 POWER GENERATORS - DC GENERATORS

- Characteristics DC generator are very similar to a DC motor, different only in their winding and commutator. - Speed Control System Diesel engines coupled to a DC generator work at constant speed. Generator output power is regulated by changing the current field.

- Example (SR4 Generator) It is essential to have a properly designed base for diesel electric power modules used on drilling rigs. Misalignment between engine and generator can cause vibration and shorten the life of couplings and bearings. Caterpillar has designed a base which provides a build-in three-point mounting system. The engine and generator are mounted by Caterpillar on this base and aligned to exacting tolerances at the factory. These power modules will maintain alignment during most rig moves. - Components The AC generator consists of:

- Apparent Power and Real power Vector diagram demonstrates the effect of power factor correction. The kVA burden of the generators is lessened by adding leading kVARS, which in turn allows the system to perform up to its full kW potential.

APPARENT POWER = (Kva):

REACTIVE POWER = (Kvar):

REALE POWER = (Kw)

where Vl = line voltage (V) Il = line current (A)

where F = angle between current and voltage

where Φ = angle between current and voltage cos Φ = power factor

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12.3 DC ENGINES

DC motors are commonly used in the oilfield because of their flexibility to control RPM and torque.

Drilling Motor GE-752 components - Use Dc motors are mainly used for the: DRAWWORK, MUD PUMPS, ROTARY TABLE and TOP DRIVE. On Offshore rigs they are also used for the: PROPELLERS, ANCHOR CHAIN WINCHES, CEMENT UNIT and JACKING CONTROLS. These motors develop a lot of heat. Cooling is achieved with air coming from a non-hazardous area.

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- Types: SHUNT and SERIES There are 2 main types of DC motors: SHUNT and SERIES The final selection between them is mainly economical. - Torque-speed of DC Shunt Motor - Torque-speed of Series Motor DC motors in series often go into overspeed at light loads.

- Advantages of AC Motors over DC Motors AC motors: - do not have any brushes and therefore do not produce sparks (critical in hazardous area) - require less maintenance - enable the drawworks and rotary table to be reversed by reversing the phase sequence. - are lighter and smaller - can operate a twice the speed

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12.5 ENGINE CONTROLS - Current Control Panel The functions of the power Control Unit include: - CONTROL - PROTECTION - MEASUREMENT OF ELECTRICAL PARAMETERS

- Control function Voltage regulator: Output tension is monitored and regulated. When two or more generators are in parallel, the voltage regulators sense voltage and current to maintain equal voltages and minimize circulating current between generators. Speed regulator: Regulates engine speed by adjusting the fuel flow. As the load increases, the speed momentarily decreases, creating a speed "error" in the governor. This error causes the fuel rack to adjust for more engine fuel and return to the original speed.

Synchronizer : Allows the generators to work in parallel at the same phase sequence, frequency and voltage. - Protection function Circuit Breaker: Protection against short circuits and overloads. Reverse Power Protection: Prevents current for circulating between generators. Power Limit: Prevents engine generator overload. Total power delivered from AC bus is monitored electronically and compared to the capacity available. Ground Fault Detection: Monitors whether electrical machines and cables are connected to the ground.

- SCR Circuit An SCR is a rectifier, it blocks power in its reverse direction and allows power to conduct in the forward direction.

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- Waveform

- Speed Command Once an electrical system is put into service, the driller's primary control is the drilling control console. Load speed is increased to the desired level by manual adjustment of the throttles.

Z series Rotary Screw Compressors for 100 % oil-free air Vibrationless, compact, trouble-free. Available engineered for the oil industry, the Z compressor provides absolutely clean air with vibrationless running, compact design, low weight an long, troublefree service life. It has air or water cooling and can also be fitted for seawater cooling. The Z has versatility of pressure from low throught high. Drive is also versatile - electric motor, turbine or diesel engine.

14. ROTARY TABLE & MASTER BUSHING INDEX 14.1 FUNCTIONS 14.2 DIMENSIONS AND CHARACTERISTICS 14.3 TYPES OF ROTARY TABLE 14.4 TYPES OF MASTER BUSHINGS 14.5 TYPES OF CASING BUSHINGS 14.1 FUNCTIONS - Rotary Table Before the TOP DRIVE introduction, the rotary table had two main functions: 1. Transmit rotation to the BHA through the Kelly Bushing. 2. Collect and support the weight of all the tools to RIH . With the invention of the TOP DRIVE, the rotary table is only used for the second function. Rotary Table

- Master Bushings The master bushings and bushing adaptors enable the rig to handle all different types and sizes of tubulars (DP. Csg, DC, etc).

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Scheme and Nomenclature

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14.2 DIMENSIONS AND CHARACTERISTICS Rotary Table from API 7K

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- Master Bushing from API 7K

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- Rotary Table "IDECO"

- Rotary Table "NATIONAL OILWELL"

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14.3 TYPES OF ROTARY TABLE The Rotary Table can run off independent motor or can be coupled with the drawworks. The independent motor can either be - electrical (most common) or - hydraulic

Rotary table with electrical motor

Rotary tables with hydraulic motor

Rotary tables with hydraulic motor were designed specifically for a TOP DRIVE. They: - Run at reduced rotary speed. - Are smaller and cheaper. Can stay in the locked position with hydraulic pressure.

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14.4 TYPES OF MASTER BUSHINGS - MPCH 37 " and 49 " - VARCO MSPC for 20 ½" to 27 ½" This MASTER BUSHING has been dimensioned for floating rigs. It can be pulled from Rotary table also when BHA is in the well.

15.1 FUNCTION AND TYPES - Function The function of the Kelly is to transmit rotation and torque to the drilling bottom hole assembly. - Types (Hexagonal kelly - Square kelly) Kellys are manufactured as square or hexagonal. - Square kelly No more utilized - Hexagonal kelly The most common is the hexagonal kelly, which offers maximum surface contact with the Kelly Bushing. Standard lengths are: 40 ft for onshore and 54 ft for offshore.

- Kelly valves Kelly valves are manually operated valves run above and below the kelly to shut off back-flow in the drill stem in the case of a kick. - Upper Kelly Cock - Lower Kelly Cock The valves are manually operated with a dedicated wrench. This is a limit for a quick intervention. The Top drive system has eliminated this with remove control operated valves.

17.3 CONTROLS - Manufacturer and API RP 8A Swivel must be checked and inspected as per the manufacturer's recommendations and API RP 8A. ENI procedures require a complete re-certification every 5 years.

- Introduction Oil well drilling with a rotary table, kelly drive bushing and 45 ft of kelly was the industry standard for years. TOP DRIVE has been one of the better innovations in the oil field in the last few years - Main functions and advantages Top drive system has 3 main functions: 1. Perform all normal hoisting requirements 2. Rotate the drill string 3. Enable circulation through the drill string Most rigs today are equipped with top drive.

Advantages: Possibility to drill stands of pipe rather than single Ability to back-ream while pooh Contains remote-controlled Inside BOP , that can be operated at distance from the rig floor - Manufacture specifications Top Drive is built in accordance with API Spec. 8A and 8C. The reference standards adopted by ENI is: ISO 13535

1. Counterbalance System A Counterbalance system offsets the weight of the TDS and provides a soft landing when TDS stabs into or out of the joint when making a connection. This prevents damage to the tool joint threads. To do this, Hydraulic cylinder connect the Swivel Bail and the elevator ear portion of the hook body.

2. Guide Dolly Assembly The Guide Dolly assembly transmits the drilling torque reaction to the Guide Rails and can provide a method for setting the entire unit aside for maintenance or to allow rig operation without the TDS if necessary.

a. Integrated Swivel & Wash Pipe The Integrated Swivel is a bearing assembly that allows transfer of the rotating load to the lifting components.

- The Swivel Wash pipe is a rotating seal that allows mud to flow to the rotating drill string. Working pressure is usually 5000 or 7500 psi.

b. Drilling Motor & Brake DC drilling motor used is essentially the same as those used elsewhere on a drilling rig to power the drawworks, mud pumps and rotary table, with same modifications: 1. A double ended armature shaft is provided to permit the attachment of an air brake. 2. Special bearings are installed to allow the motor to operate in a vertical orientation. The shaft extension on the commutator end of the motor is used to attach an Airflex 16VC600 air brake that with 90 psi air pressure gives 35.000 ftlbs brake torque.

c. Torque Wrench The torque wrench has a clamping Jaw for standard tool joints from 5 " to 7 3/8". Different size can also be handled.

- Torque Wrench Assembly

- Torque Wrench Control manifold

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Torque Wrench - Assembly

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d. Link Tilt The link tilt allows the elevators to move off of well center to pick up a joint from the mousehole. It also helps the derrickman to handle pipe more easily

5. Top Drive Control System

- Scheme: Top Drive Control system

- Control panel

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6. Top Drive Auxiliary Tools - Wireline Adapter tool

- TV camera system It's a system with one or more cameras installed at different level of Derrick to allow the driller to monitor the operations .

18.4 INSPECTIONS TOP DRIVE system, as with traditional hoisting equipment, must be checked and inspected periodically as per the manufacturer's recommendations and API RP 8B or related ISO (International Organization for Standardization) 13534. ENI policy requires the Category IV inspection (as per API RP 8B and ISO 13534) every 5 years.

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19. RIG FLOOR MUD MANIFOLD INDEX 19.1 FUNCTION 19.2 TYPES 19.3 COMPONENTS - Rotary Hose and Vibrator Hose - Mud Valve - Quick Unions - Pressure Readings 19.1 FUNCTION - Description The mud manifold is composed of pipes and valves. It connects the high pressure mud pumps to the injection head in order to circulate the drilling mud down the DP. There are several outlets on the mud manifold to connect pressure transducer. This allow the crew to monitor the "stand pipe pressure"

19.2 TYPES - Single Stand Pipe - Dual Stand Pipe

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- Dual Stand Pipe 5000 psi w.p. for Land Rig

- Dual Stand Pipe 7500 psi w.p. for Land Rig

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19.3 COMPONENTS 1. Rotary Hose and Vibrator Hose 2. Mud Valve 3. Quick Unions 4. Pressure Readings 1. Rotary Hose and Vibrator Hose Definitions (API 7K) - Rotary drilling hose Rotary drilling hose is used as the flexible connector between the top of the standpipe and the swivel that allows for vertical travel. It is usually used in lengths of 45 ft (13.7 m) and over.

- Rotary vibrator hoses Rotary vibrator hoses are used as flexible connectors between the mud pump manifold and the standpipe manifold to accommodate alignment and isolate vibration. They are usually used in lengths of 30 ft (9.2 m) or less.

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Rotary Vibrator and Drilling Hose Dimensions and Pressures

2. Mud Valve - Features A gate valve uses a closing mechanism different than a ball valve. In the gate valve a blank plate is positioned across the flow path to halt fluid flow. When the valve is opened, the plate is moved in a manner such that a section of the plate containing an orifice is positioned across the flow path which thus allows fluid movement through the orifice. Gate and seat are easy changeable for redressing.

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- Use and Connections Type Valve dimension should be proportional to the flux speed. 20 ft/s (6 m/s) to limitate the wear. Valves connections could be flanged, welded or threaded. API rules are against threaded connections since 2" 5000 psi w.p. ENI policy is against threaded connections on the mud manifold. - Drawing, working pressure, dimensions Nominal dimensions are referred to the nominal gauge of the line connected to the valve. Most commons size are : 2 -3- 4- 5 -6 inch. Working pressures are: 1.000, 2.000, 3.000, 5.000, 7.500 psi.

HIGH PRESSURE MUD PUMPS 20.1 PRINCIPLES - Duplex Pump / Triplex pump Hi-pressure mud pumps: In a Duplex Pump the piston discharges mud on one side of the piston and at the same time takes mud in on other side. In a Triplex pump the piston discharges mud only when it moves forward in the liner. In the Oilfield, duplex pumps have been replaced by triplex pumps. Triplex pumps of the same power, are smaller and lighter than duplex pumps. They also provide an uniform flow.

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20.2 NOMENCLATURE Pistons are moved with a shaft by an electrical engine or a diesel engine. The pump is divided in 2 parts: - POWER END - FLUID END

- Installation and Primary Purpose A pressure relief valve must be installed in the discharge line immediately beyond the pump. Its purpose is primarily to protect the pump and discharge line against extreme pressures that might occur when a bit becomes plugged.

Pressure Relief Valve - Installation - Use of the Relief Valve The relief valve should be used to limit the pressure in accordance with the pump manufacturer's rating for a given liner size.

Pressure Relief Valve - Scheme

Safety Valves

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20.5 FLOW RATE AND EFFICIENCY CALCULATION - Theoretical Flowrate

where Pt = theoretical flow rate (l/min) D = Liner diameter in mm L = Length of stroke in mm Vliq = Output volume per stroke SPM = strokes per minute - Efficiency Real flow rate must be calculated with the pump efficiency, which varies according to the state of the valves, the supercharging and the type of fluid. In the best case it is 0.98 for a supercharged triplex pump. Usually a normal average is between 0.95 - 0.97

- Primary purpose The primary purpose of the centrifugal precharge pump is to keep the mud pump from being starved by maintaining a positive pressure in the suction line. Total head doesn't change depending by type and weight fluid. It changes only the final pressure.

21.1 FUNCTION - Use of Mud Mixing Equipment The mud mixing equipment is used to accomplish the following: - Prepare and mix mud - Maintain mud weight and properties while drilling the well. Mud mixing must be done at the highest pump rate, to avoid decantation and grumes of the solid part (barite, bentonite, polymers, etc). Mud Mixing System

NOTE: event of a kick The mud mixing system must enable personnel to mix as much mud as required, as fast as possible, in the event of a kick.

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21.2 MIXING EQUIPMENT

Mud mixing system includes: - Centrifugal pumps - Funnel with nozzle and Venturi pipe - Charging hopper Centrifugal pump must have: - a flow rate of about 3000-3200 liters/min and - a total head of 70 - 75 ft.

- SILOS Most rigs have a system to stock bulk barite. The number of silos required depends on the kind of well, depth, overpressures and distance to the logistic base. The entire storage system has an air compressor, one or more silos, and a surge tank. - Air Compressor for Silos with Electric Motor Air Compressor with Electric Motor COMPRESSOR: Gardner-Denver WAQ-Single Stage-300 SCFM @ 40 PSI-Water Cooled - With Radiator and Air-to-Air Aftercooler-6 Cylinder ELECTRIC MOTOR 50 HP-230/460 Volt - 3 Ph-60 Hertz - 1750 RPM-Open - T.E.F.C. (Totally Enclosed, Fan Cooled), or Explosion Proof Enclosure

- Air Compressor for Silos with Diesel Engine Model H-05 Eni Corporate University

- Gravity Type Surge Tank Shown is a 70 cu ft non-pressurized surge tank. This economical unit is provided with sight glasses for level indication but high and low level indicators may be specified

- Pressurized Surge Tank Shown is a 220 cu ft pressurized surge tank. It may be specified with or without weighing device. High and low level indicators are also optional. Where weight is critical, tanks may be constructed from alluminium alloys. Choice of alloys will depend on climatic conditions.

22.1 GENERAL - Mud Pits Overview The Mud Pit enable the rig crew to: - Contain the drilling mud in a close system - Monitor the physical and reological characteristics of the mud - Monitor the well lost circulation - Control kicks Mud Pit Features

Reserve-Active Mud Pits - Supply Mud Pit System The supply system is used to prepare mud for emergency response or for next drilling phase. The capacity of the supply system is a compromise between economic and technical / operative necessities.

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22.2 TYPES

- Parallelepiped Shape Dimensions are usually choose on the basis of transportation needs. These are the most common pits.

- Cylindrical Shape with Truncated Cone Base They are engineered to reduce at the minimum the decabontation phenomenom. It's an innovative type, not so much used so far.

- Sand Trap The bottom of the mud pit shall have the right shape to facilitate good solids extraction. The following is an example of the sand trap below the shale shaker. - Sand Trap - Scheme

b. Agitators (hydraulic, mechanical) Mud Phases - Mud agitations in a pits Mud consist of a liquid phase and a solid phase. In order to avoid the separation of these two phases, it's necessary to keep the mud moving at all times.

- Scheme Mechanical agitators These are moved by electric motors through a gear reducer. - Home made Agitator 1 - Home made Agitator 2

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Home made Agitator 1

Home made Agitator 2

- Flow types Based on the impeller's configuration they can create: - Radial flow; the most commonly used - Axial flow

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- Agitator Design Based on Pit Dimensions Common practice is to install one agitator each compartment with length of 1.3 and a width 1.5. Once the compartment has been established the maximum weight of mud to be agitated is determinate, use the diagram to find the correct impeller diameter and motor. Use the volume of mud in the compartment and the pumping rate to determine the agitation time. The optimum value shall be below of 35 seconds. Agitator Design

23.1 INTRUDUCTION There are several lines on surface in a drilling rig. They can be for high pressure, low pressure or discharge lines. Everyone of these lines has to be dimensioned depending by the use, the kind of fluid, the general conditions (Flow rate, pressure, temperature, etc). For very long lines we have also to consider the pressure losses, for example in the kill and choke lines of a semisub or even for the stand pipe manifold with the rig pumps far from the rig floor.

- Results of pipe sizing A. Pipes with an I.D. that is too small cause high flow velocities and turbulence. This results in high friction losses, power wastege, and high maintenance costs. B. In pipes with an I.D. that is too large, solids tend to settle on the pipe bottom and restrict size. These also cost more initially. C. Whit the correct pipe I.D., the flow velocity is optimum and the lines remain clean. Investment and maintenance costs are optimum.

24. TRIP TANK INDEX 24.1 DESCRIPTION 24.2 DIMENSIONS 24.3 CONFIGURATION 24.1 DESCRIPTION - Monitoring of the mud It is necessary to monitor the amount of mud that exits or enters the hole as the drilling string is run in or out. The monitoring, or measurement, can be done either by using the rig pumps and calculating the number of strokes required to fill the hole, or by using a trip tank. Trip Tank

- Function A TRIP TANK is any pit or tank in which the mud volume can be measured accurately to within +/- 1.0 bbls. As the pipe is pulled from the hole, the mud from the tank is allowed to fill the hole as needed, which at the same time denotes the amount of mud being used. The mud fills the hole by a pump with a return line from the bell nipple to the tank. A continuous fill up device doesn't require as much of the driller's attention.

24.2 DIMENSIONS - Trip tank dimensions Trip tank dimensions are a compromise between reading 100 liters variations and having to fill the tank too often. Usually, they are dimensioned to achieve a 3 inches height variation for a 5 DP stand. The Centrifugal pump must have a sufficient flow rate to empty the tank in a few minutes. ENI Well Control police stipulates that the minimum capacity of trip tank should be 5 m3 (30bbls).

- Level indicator The Level indicator is a float connected to a graduated gauge stick positioned on the rig floor and visible to the driller. - Modern systems have the float connected to an electronic gauge or ultrasonic device.

25.1 BENEFITS OF SOLIDS REMOVAL - Solid Removal A large quantity of solids in the mud can cause many problems during drilling. It also results in high mud treatment costs trying to mantain the shape of the mud. The purpose of solid removal equipment is to contain the percentage of solid in the mud at an acceptable level. Solids Removal Systems - Offshore Rig Solids Removal Systems – Small Land Rig

- Equipment Lay out This equipment is used in succession because each of them is engineered to remove solids of a progressively smaller size. At the moment the trend is to equip new rigs with shale shakers that are more efficient and also function as a desander, desilter and sometimes as a mud cleaner. 25.4 SHALE SHAKER The Shale shaker is the first stage of solids removal as the mud comes from the well. Its treatment capability is determinated by the size of screen and to the mud characteristics.

Schematic of SOLIDS REMOVAL SYSTEM

Nomenclature API Standard Shale Shaker - Cascade system Drilling Rigs have more than one shale shakers installed in parallel in order to better distribute the mud flow coming from the well. Shale shakers can also be installed in succession (cascade system) in order to get a first cuttings removal (bigger sizes) on the primary and a following one of smaller cuttings on the secondary. Cascade system

Shale shaker differentiates also by their vibration capability that is due to engine the Round Per Minute and therefore, of rack's speed; more high it is, more is the mud thrown force on the shale shaker screens. Empirically, this force is identified by g factor that is calculated as follows: Run of vibration motion (inc x RPM 2) "g" factor = ⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯ 70400

- Screen mesh Screen mesh is the number of meshes per inch; that correspond to number of mesh per inch. API Specification has standardizide a different way to identify the shale shaker's screens. For instance, 80 x 80 (178 x 178, 31,4) means that the screen has 80 mesh of square shape with a square light of 178 micron and a passing light of 31,4% on the total area.

Mud is sent to a cyclone through a dedicated centrifuge engineered specifically for this purpose. The drilling mud must enter the cyclone tangentially with high flow and pressure. Here it acquires high velocity. Centrifugal force separates the solid phase from the liquid phase, sending the solids to the lower exit (Underflow) and the liquids to the upper exit (Overflow).

- Cone Size and Use The wide part of a cone can vary between 4 to 12 inches. Cones are usually installed in parallel to adequately treat the mud.

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- DESANDER - Desander cones A desander uses cones with a diameter of 8 to 12 inches. The bigger the cone the larger the solids discharged. - Particle Removal Desilter remove particles in the range of 15 micron.

Desander: Particle Removal

- DESILTER - Desilter cones A desilter uses cones with a diameter of 4 to 5 inches, and can use from 8 to 20 depending on the volume of mud flow to be treated. - Particle Removal Desilter remove particles in the range of 15 micron. Desilter: Particle Removal - Desilter Operation Proper fluid balance between pit compartments is very important. Desilter Operation: WRONG Desilter Operation: RIGHT

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25.6 MUD CLEANER - Functionality The mud cleaner is a combination shaleshaker/desilter that was introduced in the early '70s. It was invented out of the necessity to reduce the volume of weighted solids (barite) discharged from the mud. A 200 Mesh screen removes drilled solids but returns mud additives and liquids back into the circulating system.

- Hydrocyclones

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- Screen particle removal

25.7 DECANTATION CENTRIFUGE

- Functioning principles The centrifuge consists of a conical body (BOWL) and a channel with helicoidally shape (CONVEYOR) They both rotate coaxially in the same direction, but the conveyor rotates a slightly lower angular speed than the bowl. Mud to be treated is introduced into the centrifuge through a mono type pump. The rotation in the bowl separates the solids from the liquids by centrifugal force. The conveyor transports the solids discharged while the liquids go back in the mud circulating system through the colloidal liquid discharge.

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Decanting Centrifuges Scheme

Scheme of Succession Centrifuges

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26. DEGASSER INDEX 26.1 FUNCTIONS 26.2 PRINCIPLES 26.3 DEGASSER TYPES - BURGESS - SWACO - WELLCO & BRANDT - DEGASSER SYSTEM for H2S PRESENCE 26.4 INSTALLATION CRITERIA 26.1 FUNCTIONS The purpose of degassers is to remove air or gas entrained in the mud system in order to insure that the proper density mud is recirculated down the drill pipe. If the gas or air is not removed, the mud weight measured in the pits may be misleading. This will result in the addition of unnecessary amounts of weight material thereby giving true mud densities down the hole that are more than desired. Gas contamination could result from: - 1. Drilling Gas - 2. Trip Gas - 3. Connection Gas - 4. Well testing

26.2 PRINCIPLES All degasser types operate on: turbulence and vacuum. - VACUUM - TURBULENCE Vacuum increases gas speed through the Mud flows in thin sheets over a series of baffles vertical vent line. arranged inside a vertical tank. The resulting turbulent flow breaks out large gas bubbles which then rise through a vent line.

- BURGESS Gas-cut mud is drawn into the rotor body by vacuum, then sprayed radially and impacted against a urethane ring, creating adequate turbulence for air and other gas removal. Gasses are removed by a vacuum blower. The degasser mud is evacuated by a center vented centrifugal pump which prohibits gas locking. The mud is pumped to the degasser mud tank through a reinforced hose.

Burgess Degasser - Scheme

- SWACO This degasser is a horizontal tank with long downward sloping baffles inside. Mud flows down these baffles in a thin layer, releasing the gas bubbles. A vacuum pump is used to remove the gas from the tank and dispose it a safe distance from the rig. The vacuum tank also reduces the internal tank pressure, drawing fluid into the tank and increasing the gas bubble size, improving removal efficiency. The jet pump discharges the degassed mud from the tank and returns it to the next downstream compartment. There is no re-mixing of released gas and fluid.

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- WELLCO & BRANDT Vacuum degassers (Wellco & Brandt) consist of a vacuum generating tank which, in effect, pulls the gas out of the mud due to gravity segregation. Some degassers have a small pump to create a vacuum while others (see picture) use the centrifugal mixing pumps to create a vacuum. It's important to note that most degassers, regardless of type, have a minimum required mud throughput for efficient operation. Wellco-Brandt Degasser

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- DEGASSER SYSTEM for H2S PRESENCE This is a mix between a Swaco degasser and a mud gas separator working in series. It's used to control a kick in the presence of H2S. The mud gas separator receives the flow of mud and gas heads from the choke manifold. The free gas is routed to the flare line. The remaining entrained gas and mud is discharged from the bottom of the separator to a modified degasser. The check valve ensures that no mud from the separator can bypass the degasser and flow into the active mud system. Degasser for H2S presence

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26.4 INSTALLATION CRITERIA - Incorrect Example Faulty degasser operation due to both high and low opening between degaser suction and discharge compartments.

27.1 PHYSICAL DATA FOR STEEL DRILL PIPE DRILL PIPE A joint of drill pipe is composed of 2 parts: the body and the tool joint. Body: central part Tool Joint: connections welded to each end of the pipe body and threaded - one box thread and one pin thread.

API 5D specifies the dimensions and characteristics of the body. API 7 specifies the dimensions and characteristics of the tool joint The ISO reference is the draft 11961. ENI requirements are defined by internal specification. Drill Pipe - Scheme

Tool Joint Hardfacing To reduce the wear on the tool joint, some contractors weld a hard-facing material on the wear area of the tool joint. In some deviated wells the hardfacing has been dangerous because it was damaging the casing with rotation. Recently technology has developed hardfacing materials producing a minimum wear on the tool joint and on the casing. ENI policy stipulates the using of "Casing friendly Hardfacing". - DEA comparation table As shown in DEA comparation table (see following table) sometimes the hardfacing has better performances than the DP without it. ENI accepts a maximum csg wear of 7%.

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- Types examples - SmoothX - SuperSmoothX

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High Torque Tool Joint Extended reach well create very high torque during drilling. Because API tool joints cannot tolerate these high torques values, a special high-torque tool joint has been developed for these applications. - GRANT_PRIDECO H-T Tool Joint -

Notes: 1. Internal pressure for new drill pipe in table 3 were determined by using the nominal wall thickness for t in the above equation and multiplying by the factor 0.875 due to permissible wall thickness tolerance of minus 12 ½ percent. 2. Internal pressure for used drill pipe were determined by adjusting the nominal wall thickness according to footnotes below Table 5 and 7 and using the nominal outside diameter, in the above Equation A.8 - COLLAPSE A.3 Collapse Pressure for Drill Pipe
Note: See API Bulletins 5C3 for derivation of equations in A.3

The minimum collapse pressures given in Tables 3, 5 and 7 are calculated values determined from equations in API Bulletin 5C3. Equations A.2 through A.5 are simplified equations that yield similar results. The D/t ratio determines the applicable formula, since each formula is based on a specific D/t ratio range. For minimum collapse failure in the plastic range with minimum yield stress limitations: the external pressure that generates minimum yield stress on the inside wall of a tube.

Pc = 2Ym [ (D/t) – 1 ] (D/t) 2

(A.2)

Applicable D/t for aplication of Equation A.2 are as follows: Grade E75 X95 G105 S135 D/T Ratio 13.60 and less 12.85 and less 12.57 and less 11.92 and less

Fatigue stress Drill pipe is subjected to cyclic stresses in tension, compression, torsion and bending. Drill pipe will suffer fatigue when it is rotated in a section of hole in which there is a change of hole angle and/or direction, commonly called a dogleg. - LUBINSKI method's LUBINSKI has developed a method for estimating the cumulative fatigue damage to pipe which has been rotated through severe doglegs. - Maximum permissible dogleg severity - Maximum permissible bending stress

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Dogleg Severity Limits for Fatigue

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TOOL JOINT STRESS - Tension - Torque - Combined Stresses

Tension - Calculations Calculations are the same as DP body. 120,000 is the minimum Yield. The critical area is 5/8 from tool joint shoulder

27.5 DRILL PIPE BRITTLE FOR H2S - Sulphide Stress Cracking SSC In the presence of hydrogen sulfide (H2S) tensile-loaded drill stem components may suddendly fail in a brittle manner at a fraction of their nominal load-carrying capability after performing satisfactorily for extended periods of time. Failure may occur even in the apparent absence of corrosion, but is more likely if active corrosion exists (Sulphide Stress Cracking SSC ). With H2S, Strength of steel between 22 and 26 HRC is suggested.

- Functions Part of the Drilling String, Heavy Drill pipe has a unit weight in between Drill Pipe and Drill Collars. They are run between Drill Collars and Drill Pipes to: 1. Create a gradual reduction of BHA rigidity between the two. 2. Reduce fatigue stress on the DP just above the DCs. 3. Reduce wall friction in vertical deep wells with high RPM. HW DP dimensions are standardized by API 7 Specifications. The relevant ISO standard is the 10407 Spec. ENI requirements are defined by internal specification.

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- HW Saves Rig Time by Reducing Trip Time HWs stand back in the rack like regular Drill Pipe

- D.C. Connection Dimensions All drill collars connections must have stress relieve/bore back features in conformance with API 7.

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- Mechanical characteristics

- BENDING STRENGTH RATIO CALCULATION - Calculation

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- Optimal Bending Strength Ratio Bending ratio is calculated knowing the type of thread and measuring, at a specific point shown in the picture, the ID and OD. For every table of determined ID, with OD we can cross the thread line and see the strength ratio on the horizontal axis.

c. Thoroughly clean box pin threads. Follow immediately with wet fluorescent magnetic particle inspection for detection of cracks. A magnifying mirror may be used in crack detection of the box threads. Drill collars found to contain cracks should be considered unfit for further drilling service. Shop repair of cracked drill collars is typically possible if the unaffected area of the drill collar permits. d. Use a profile gauge to check thread form and to check for stretched pins. e. Check box counterbore diameter for swelling. In addition, use a straight edge on the crests of the threads in the box checking for rocking due to swelling of the box. Some machine shops may cut box counterbores larger than API standards, therefore, a check of the diameter of the counterbore may give a misleading result. f. Check box and pin shoulders for damage. All field repairable damage shall be repaired by refacing and beveling. Excessive damage to shoulders should be repaired in reputable machine shops with API standard gauges.

- VARCO BJ Air Operated Air Operated BJ center latch elevators are recommended for use with BJ power pipe handling system. These elevators will close and latch automatically on contact with drill pipe or collar which is to be raised or lowered. The elevators are opened by remote control, by the driller.

- BLOHM VOSS Air Operated

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- ELEVATORS for DP & DC (with variable size bushings) - BLOHM VOSS Air Operated These elevators have replaceable bushings to fit different sizes of pipe. They can be operated manually or by remote control. BLOHM VOSS Air Operated: Pipe Sizes range

- ELEVATORS for DC - DC lifting subs Most contractors have decided, for safety reasons, not to use elevators for drill collars with upsets. Due to drilling wear, the elevator contact area on the collar is decreased and can become very dangerous. Instead, contractors prefer to use DC lifting subs. They add to trip time, but significantly increase safety. - DC lift Drill Collar Handling System Tripping time are reduced because it's not necessary to change out the elevator.

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DC lifting subs

DC lift Drill Collar Handling System

- Varco BJ Type SLA-100 Size, Type and Capacity

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- ELEVATORS for Casing Special elevators are used for running casing. The most common manufactures are Varco and BJ. Two main types: - Side Door Type - Slip Type

- Side Door Elevators These are used for light weights or for the first joints of csg.

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Slip Type - Slip type Elevators - Ton Elevator / Spide Varco Type

- Slip type Elevators Operated manually or by remote control, these can be used as elevators or clamps.

29.5 TONGS DP and DC make-up occurs in two stages: - Spin the two tool joints together (spinning) - Torque connection to tighten it (Make-up torque) Viceversa for Break-down operations. For DP and DC make up torque values are indicated in API RG 7G. Two tongs are used and positioned on the 2 tool joints. The top one for the torque and the bottom one as back up tong. SPINNING WRENCHES - Spinning chain Spinning was historically done with the spinning chain; but this was dangerous and the safety of all on the drill floor depended on the skill and experience of the man throwing the chain. - Spinning wrench The automatic spinning wrench is now replacing the spinning chain in many drilling rigs.

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Spinning chain

Weatherford Drill Pipe Spinner

VARCO SSW30 Spinning wrench

VARCO SSW30 – Specifications

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TONGS for DP - DC & CASING Manual - Operational Two tongs are used and positioned on the 2 tool joints. The top one for the torque and the bottom one as back up tong. Torque is applied by pulling the top tong with the cathead. For high torques a hydraulic piston is used for pulling (Ezy Torque).

Ezy Torque Drilco

- Torque applied - Torque Indicator Torque applied is the result of the pull multiplied The pull should be applied as perpendicular as by the tong arm length. possible to the arm to avoid false values.

- Ezy Torque The EZY-TORQUE is used for high make up torques (DC > 9.1/2 OD) when the cathead is not enough.

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TONGS for DP - DC & CASING Automatic

- DP torque Wrench Making up and breaking out made simple. The hydraulically powered TW-60 makes up and breaks out drill pipe tool joints and drill collars from 4 to 8 inch OD. Torque is adjustable and can be pre-set to the required value

The pipe rack is the place where tubulars are stored and positioned before lifting them up the rig floor. In the photo shows Casings already equipped with centralizers al ready to be run in the well.

Pipe rack: Casings

29.7 FINGERBOARD The Fingerboard purpose is to rack the tubulars while tripping.

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29.8 PICK UP & LAY DOWN MACHINE The pick up and lay down machine was designed to move tubulars without damaging them and move heavy. Pick up and lay down machine

29.9 CSG STABBING BOARD

Casing Stabbing Board is a personnel mobile platform used for csg operations. Its installed in the derrick. It can be moved up and down to enable the operator to guide the Csg joint from top side. Its equipped with several antifall devices.

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30. DIVERTER INDEX 30.1 FUNCTION 30.2 TYPICAL CONFIGURATION 30.3 TYPES AND CHARACTERISTICS 30.4 INSPECTIONS 30.1 FUNCTION - Description The Diverter is installed on the conductor pipe before drilling of first phase of the well and is designed to keep personnel and Rig safe. It consist of an annular type blow out preventer and is designed to divert shallow gas away from the well area while drilling surface hole. In doing so, the well remains open but diverting the pressure avoids fracturing a formation. - Manufacture specifications Diverter system are manufactured according to API 16A and RP 64. The relevant ISO standard is the 13533 Spec. ENI requirements are defined by "Well control policy" and an internal specification. 30.2 TYPICAL CONFIGURATION - Off-shore application (API RP 64) Schematic arrangement for an off-shore application, as per API RP 64 recommendations.

- Hydril example with SXV spool arrangement This integral type spool with diverter has the advantage of remote controls, eliminating the use of lateral valves.

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- SXV MSP Engineering Data

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-Typical configuration on Saipem's Rigs Typical configuration on Saipem's medium and high power Rigs

- Diverter Installations - Diverter with spool for land rig - Diverter with spool installed on land rig

- Diverter valve

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30.3 TYPES AND CHARACTERISTICS - Hydril MSP The 29 " Diverter is the most commonly used. It allows the running of 27 " bit. For fast moving type Rigs, uses the 20" annular BOP The MSP 29-1/2"-500 requires only closing pressure. Seal off is effected by hydraulic pressure applied to the closing chamber which raises the piston, moving the packing unit radially inward into a sealing engagement. Any normal closing unit having a separate regulator valve for the annular BOP and sufficient accumulator volume can be used to operate the MSP.

30.4 INSPECTIONS The Diverter System shall be inspected (modally and frequency) according to the manufacturer's recommendations and as per API RP 53. ENI requirements are defined by an internal specification.

31.1 FUNCTION The annular preventer is part of the BOP STACK installed on the well head once the anchor casing is run and cemented in the hole. The BOP is the second and final safety device to handle the uncontrolled flow of formation fluids (hydrostatic mud pressure is the first) from well. The annular BOP is engineered to close tightly on any cylindrical body with dimensions as large as the maximum opening ID of the BOP to dimension as small as the fully closed position. The annular BOP can close on Drill Pipes, Drill Collars, Casing, Tubing, Tool joints the kelly and wire line. It is not request, as with the Ram BOP, to check the position of Tool Joint before closing.

- Special operation: Stripping Once closed on the Drill Pipe, these can be reciprocated and stripped.

- Manufacture specifications Annular Preventer are manufactured according to API 16A. The relevant ISO standard is the 13533 Spec. ENI requirements are defined by "Well control policy" and an internal specification.

- Operational fluid pressure The operational fluid pressure is relatively low and can be regulated by the well pressure and by the diameter of the body being closed in the BOP. Usually the BAG BOP's are wellpressure assisted. This means that the well pressure helps to keep the BOP closed against the pipe body.

Closing and Opening Pressure

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31.3 TYPES AND CHARACTERISTICS Manufacturers of Annular Preventers include: - CAMERON - HYDRIL - SHAFFER - CAMERON BOP The most common types are "D" and "DL" - Engineering Features A quick-release top with a one-piece split lock ring permits quick packer change out with no loose parts involved. The design also provides visual indication of whether the top is locked or unlocked DL Annular Blowout Preventer

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- Section view of CAMERON "DL" Type - The Cameron DL BOP is shorter in height than comparable annular preventers and features light weight for use on platforms and rigs where weight is a consideration. - Twin seals separated by a vented chamber positively isolate the BOP operating system from well bore pressure. High strength polymer bearing rings prevent metal-to-metal contact and reduce wear between all moving parts of the operating systems.

- Others Engineering Features All Cameron DL BOPs are manufactured to comply with NACE MR-01-75 for H2S service. Popular sizes of the DL BOP are available with high performance CAMULAR annular packing subassemblies. The Cameron DL BOP is available in sizes from 7-1/16" to 21-1/4" and in working pressures from 2000 to 20,000 psi working pressure and in single or double body configurations.

- Natural Rubber Is compounded for drilling with water-base drilling fluids. Natural rubber can be used at operating temperatures between

- Nitrile Rubber

- Neoprene Rubber Is for low-temperature operating service and oil-base drilling fluids. It can be used at operating temperatures between -30 F to +170 F (-35 C to 77 C)

(a synthetic compound) is for use with oil-base or oil-additive drilling fluids. It provides the best service with oil-base muds, when operated at temperatures between -30 F to 255 F (-35 C to 107 C) 20 F to 190 F (-7 C to 88 C)

- Shaffer Bag Bop Packing - Suitable for H2S and Arctic Service Shaffer standard Sphericals meet all applicable American Petroleum Institute (API) and National Association of Corrosion Engineers (NACE) requirements for internal H2S service. Field conversion for external H2S service involves changing only the studs, nuts and lifting shackles. - Steel Segments Reinforce sealing Element Steel segments molded into the elements partially close over the rubber to prevent excessive extrusion when sealing under high pressures. These segments always move out of the well bore when the element is worn far beyond normal replacement condition.

31.4 INSPECTIONS The BOP Bag Preventers shall be inspected (modally and frequency) according to the manufacturer's recommendations and as per API RP 53. ENI requirements are defined by an internal specification that stipulates the Bag BOP shall be recertified by a Manufacturer authorized workshop at least every five years. Eni Corporate University 331

32.1 FUNCTION The BOP is the second barrier to stopping uncontrolled formations fluids from coming into the well. The BOP is only used when the first barrier (hydrostatic mud pressure) has failed. In addition to the bag preventer, a number of rams are used. ENI "Well control policy" stipulates the minimum BOP stack requirements. (In terms of numbers for surface and underwater BOP)

The number and type of rams in the BOP stack depends on: - Maximum pressure expected in the well. - BHA dimensions (OD). BOPs are designed to enable the crew to easily change the size and type of rams. - Types of rams The types of rams in use include: - Pipe Rams - Variable Rams - Blind Rams - Blind / Shear Rams

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- Manufacture specifications RAM Preventer are manufactured according to API 16A. The relevant ISO standard is the 13533 Spec. ENI requirements are defined by "Well control policy" and an internal specification. Bop Rams - Parts

- increases the rams' sealing integrity - maintains the seal in case of hydraulic pressure loss Increased well bore pressure actually improves seal integrity. - Working System Working System for ram BOP opening and closing CAMERON type U If leaks were observed, replace the seals and repeat the test.

Working System for ram BOP opening and closing - Ram Locking System (ram lock) A manual locking system is standard for the U BOP. It consists of a locking screw housing and a locking screw. The locking system is not in the operating system, and can be removed without disturbing any operating system seals. The locking screws are "run in" when the rams are closed, locking the rams in the closed position. The screws must be backed out before the rams can open. - Bonnets There are three types of bonnets available for some U BOPs: - pipe bonnets (pipe rams) - standard shear bonnets (shear rams) - large bore shear bonnets (shear rams) - super shear Bonnet - Large Bore Shear Bonnets The large bore shear bonnet is available for many U BOPs as a replacement for the standard shear bonnet. It was developed to meet a need for greater shearing pressure brought about by: - heavier walled and higher strength pipe - greater variance in pipe ductility Large bore shear bonnets eliminate the operating cylinder. This increases the available closing area 35% or more, which increases closing force by 35% or more. The large bore shear bonnets also have a different operating piston, and changes in the machining of the intermediate flange and bonnet. Eni Corporate University 337

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Note: Some shear bonnets can be converted to large bore shear bonnets

- Super Shear Bonnets A BOP equipped with Super Shear Bonnets and non-sealing Super Shear Rams provides a solution to the problem that can result when shearing becomes necessary and a drill collar is in the bore. - Tandem Booster Tandem boosters can be used with the U shear ram. They increase the force available to shear pipe by 100% - 124%, without increasing the wear an tear on the packers.

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Ram Types - Ram selection A wide selection of ram is available to meet all applications.

- Pipe rams Pipe rams close and seal on one specific size of pipe. They are also used for "hang-off". With hang-off, the ram is used to suspend pipe or casing by closing underneath a tool joint. Note: Older pipe rams may not be hang-off rams.

- Blind rams

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- Shear rams CAMERON manufactures 3 types of shear rams: 1. SBR (Shearing Blind Ram); which is the most common type and is available for all pipe diameters. 2. H2S; equipped with an interchangeable blade with the right degree of hardness to carry out shearing and H2S service. It is available for 13 5/8" models and for 5.000 / 10.000 psi. 3. DS; it is the most recent model: it has a wider sealing zone, which ensures a better sealing after shearing. It is available for 11" and 13 5/8" models and for 5.000 /10.000 psi.

- Shearing Capability

- Variable bore rams (VBR) The VBR seals on several sizes of pipe or hexagonal Kelly within its specified size range. A typical range is from 5 " to 3 ". Other size ranges such as 7" to 4 " are available upon request. VBRs are not intended for long-term stripping. Eni Corporate University 340

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- Table VBR Hang-Off

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- FLEXPACKER Ram Packer The FLEXPACKER is designed to complement the VBR range by closing and sealing around several specific diameters of tubing and pipe.

- Features The Ram Assembly provides reliable seal off the wellbore for security and safety. The Ram accommodates a large volume of feedable rubber in the front packer and upper seal for long service life. The Field Replaceable Seal Seat provides a smooth sealing surface for the ram upper seal. The seal seat utilizes specially selected and performance effective materials for maximum service life. The field replaceable seal seat eliminates shop welding, stress relieving, and machining for repair, thus reducing downtime and direct repair costs. Hinged Bonnets swing completely clear of overhead restrictions (such as another BOP) and provide easy access for rapid change to reduce downtime. Manual Locking utilizes a heavy-duty acme thread to manually lock the ram in a sealed-off position or to manually close the ram if the hydraulic system is inoperative. Ram Seal Off is retained by wellbore pressures. Closing forces are not required to retain an established ram seal off.

- HYDRIL variable rams Universal Seal Off The HVR gives a universal seal off feature especially useful on tapered drill strings and drill pipe that does not have a constant diameter over its length. Two ram BOPs with HVRs can be used on a tapered string to provide a backup for all drill pipe sizes. This application eliminates having one pipe ram for small diameter pipe and one for large diameter pipe. If a BOP stack is assembled with a blind or blind/shear ram and two sets of Hydril Variable Rams 3-1/2" to 5-1/2", providing the backup seal off capability needed on a tapered string. The HVR is therefore ideally suited for subsea use by expanding the seal off capability of one ram assembly within a BOP.

- Main Features Self-draining body has a ram compartment with skids to support the rams and a sloped bottom which allows mud and sand to drain back into the well bore. This keeps the ram cavity free of caked mud and debris so that the rams stay ready for action. Single, double and triple models are available. Full environment H2S trim, conforming to API and NACE requirements, is available. Arctic models are available which meet API specifications for lowtemperature service.

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- Operating system - Hydraulic passages Hydraulic passages drilled through the body eliminate the need for external manifold pipes between the hinges. Each set of rams requires only one opening and one closing line. There are two opening and two closing hydraulic ports, clearly marked, on the back side of the BOP. The extra hydraulic ports facilitate connecting the control system to the preventer. - Hydraulic pressure A hydraulic closing unit with 1,500 psi output will close any Model SL ram BOP with rated working pressure in the well bore, except for the 7 1/16", 11" and 13 5/8" - 15,000 psi BOPs, which require 2,200 psi. However, these units will close against 10,000 psi well pressure with less than 1,500 psi hydraulic pressure. A 3,000 psi hydraulic pressure may be used, but this will accelerate wear of the piston seals and the ram rubbers. A 5,000 psi hydraulic pressure test is applied to all Model SL cylinders at the factory. However, it is recommended that this pressure not be used in the field application.

Operating system Ram BOP SHAFFER Locking system Ram BOP SHAFFER locking system - Automatic lock system - Manual lock system - Automatic lock system Model SL Poslock & Multilock Systems SL preventers equipped with Poslock or Multilock pistons are locked automatically in the closed position each time they are closed. The preventers will remain locked in the closed position even if closing pressure is removed. Open hydraulic pressure is required to reopen the pistons.

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The Poslock and Multilock systems both utilize locking segments to achieve the positive mechanical lock. The Poslock System has one set of segments and provides for one position locking which is the maximum requirement for standard pipe rams. The Multilock System has two sets of segments thus allowing a range of locking positions which is required when multirams are utilized. Multilocks accommodate for most multiram ranges offered, however the ranges covered for a selected multiram should be verified with the SHAFFER representative. The hydraulics required to operate the Poslock are provided through opening and closing operating ports. Operation of the Poslock requires no additional hydraulic functions, such as are required in some competitive ram locking systems. - Close Position When closing hydraulic pressure is applied, the complete piston assembly moves inward and pushes the rams into the well bore. As the piston reaches the fully closed position, the locking segments slide toward the piston O.D. over the locking shoulder while the locking cone is forced inward by the closing hydraulic pressure. The locking cone holds the locking segments in position and is prevented by a spring from vibrating outward if the hydraulic closing pressure is removed. Actually, the locking cone is a second piston inside the main piston. It is forced inward by closing hydraulic pressure and outward by opening hydraulic pressure.

- Open position When opening hydraulic pressure is applied, the locking cone moves outward and the locking segments slide toward the piston I.D. along the tapered locking shoulder. The piston is then free to move outward and open the rams.

NOTE ( Pistons adjustment ) Poslock and Multilock pistons are adjusted in the factory and normally do not require adjustment in the field except when changing between pipe rams and shear rams. The adjustment is easy to check and easy to change.

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Manual lock system - Model SL Manual-Lock System Manual-lock pistons move inward and close the rams when closing hydraulic pressure is applied. If desired, the rams can be manually locked in the closed position by turning each locking shaft to the right until it shoulders against the cylinder head. Should hydraulic pressure fail, the rams can be manually closed and locked. They cannot be manually reopened. The manual locking shafts are visible from outside and provide a convenient ram position indicator. Threads on the manual locking shaft are enclosed in the hydraulic fluid and are not exposed to corrosion from mud and salt water or to freezing.

- Open position Rams are opened by first turning both locking shafts to their unlocked position, then applying opening hydraulic pressure to the pistons, which move outward and pull the rams out of the well bore.

- Close Position Manual lock-piston in closed and locked position

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- SHAFFER BOP Rams - Model SL-D rams Model SL-D rams will support a 600,000pound drill string load when a tool joint is lowered onto the closed rams. These rams comply with API and NACE H2S specifications. A patented, *H2S-compatible, hard inlay is welded around the pipe bore to cut into the 18 taper on the bottom of the tool joint and from a supporting shoulder. The remainder of the ram block is alloy steel with hardness below Rc22. - SL Ram Mounting SL Rams Mount Horizontally on Preventer Rated for Working Pressures of 10,000 and Lower except 7 1/16" 10,000 psi

- Shear Pipe Operation Type 72 shear rams shear pipe and seal the well bore in one operation. They also function as blind or CSO (Complete Shut-Off) rams for normal operations. The hydraulic closing pressure normally required to shear drill pipe is below 1,500 psi accumulator pressure in BOPs with 14" pistons. However, this varies, depending on the size, weight and grade of pipe.

- Multy Rams

32.4 INSPECTIONS The BOP Ram Preventers shall be inspected (modally and frequency) according to the manufacturer's recommendations and as per API RP 53. ENI requirements are defined by an internal specification that stipulates the Ram BOP shall be recertified by a Manufacturer authorized workshop at least every five years.

33.1 FUNCTION - Description Accumulators produce and store hydraulic energy to be used when BOP must be closed rapidly because of emergency conditions. It's equipped with the necessary controls to actuate BOP's and hydraulic valves during drilling and in case of a blowout. BOP control system must provide : - A minimum pre-determined pressurized volume to operate all BOP functions in an emergency situation. - Reasonable accumulator recharge time.

- Nomenclature The Accumulators is composed by: - a tank containing hydraulic fluid (oil) at atmospherich pressure; - one or more high-pressure pumping units to pressure fluid; - nitrogen precharged bottle to store pressurized fluid. The high-presure control fluid is conveyed to a manifold and sent to closing mechanisms through provided control valves.

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- Manufacture specifications Surface BOP Control System are manufactured according to API 16D and API RP 53. ENI requirements are defined by "Well control policy" and an internal specification".

33.2 RESPONSE TIMES - Response times API RP 53 and ENI Well Control Policy stipulate: - Closing response for a Ram BOP max 30 seconds - Closing response for a BAG BOP 18" max 30 seconds - Closing response for a BAG BOP >18" max 45 seconds - Pumps system charging time The subsea control system should have a minimum of two independent pump systems (i.e. one electric and one pneumatic or two electric powered by two separate electrical power sources). The combination of all pumps should be capable of charging the entire accumulator system from the established minimum working pressure to the maximum rated system pressure in fifteen minutes or less.

Accumulator - ACCUMULATORS CAPACITY

Accumulator Pumps

- Accumulator Dimension The accumulator is dimensioned depending on the required fluid total volume to carry out a given number of closing-opening operations (Volumetric capacity) and on the bottle fluid actually usable (Usable fluid volume). For the accumulator dimensioning the following values are to be considered: - precharging pressure; it is the initial pressure with bottles filled with nitrogen only (1000 psi); - working pressure; it is the final pressure with bottles filled with control fluid (3000 psi). - minimum working pressure; it is the minimum pressure value which allows the accumulator to be used (which is 200 psi above the precharging pressure) Eni Corporate University 355

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ENI requirements are more strict than API. Surface BOP accumulator capacity by ENI Well Control: The capacity of the accumulators should be, at least, equal to the volume (V1), necessary to close and open all BOP functions installed on stack once, plus 25% of V1. The liquid reserve remaining on accumulators should still be the minimum operating pressure of 1,200 psi (200 psi above the precharge pressure) V1 ⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯ Pa / Pmin – Pa / Pmax

- ACCUMULATOR UNIT Accumulators produce and store hydraulic energy to be used when BOP must be closed rapidly because of emergency conditions. It is equipped with the necessary controls to actuate BOP's and hydraulic valves during drilling and in case of a blowout. - Components and Nomenclature The accumulators is composed of: - a tank containing hydraulic fluid (oil) at atmospheric pressure; - one or more high-pressure pumping units to pressurise fluid; - nitrogen precharged bottles to store pressurised fluid The high-pressure control fluid is conveyed to a manifold and sent to closing mechanisms through provided control valves. - Accumulator Unit - Nomenclature

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- Bottles Bottles must work at pressure values below their maximum working pressure value. Precharging pressure must be read whenever an installation is started and checked and regulated in the following, if necessary. To accomplish pressurisation use nitrogen. - Valves and pressure gauges When the bottles are installed on more than one manifold, suitable valves must be installed to allow isolation of each manifold. The working pressure of these valves must be the same as that of the accumulator and must be kept open, except when the accumulator is not working. A pressure gauge for the precharging pressure check must always be available. - Precharge and Full charge - Empty precharged at 1000 psi - Full Pressurized at 3000 psi

Accumulator Precharge and Full charge - Charging pumps Each accumulator must be equipped with a sufficient number of pumps to carry out the following: 1. pump capability; when the bottles are excluded, the pumps must allow, within a maximum twominute time: - close the annular BOP - close one pipe-ram BOP with the same diameter as the pipes being used - open the hydraulic valve on the choke line - raise the manifold pressure to a value which equals the precharging pressure plus 200 psi (see pump capability test) 2. charging time; the use of all of the pumps must allow the accumulator to be charged from the pre-charging pressure value up to the maximum working pressure value within a maximum 15 minute time.

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3. working pressure; the installed pumps must keep a working pressure equal to the accumulator working pressure (3000 psi) 4. power requirement; the necessary power to allow the pumps to function must always be available to allow them to start automatically whenever the pressure value decreases below 90% of the working pressure (2700 psi for 3000 psi working pressure values). - For safety reasons, two or three independent power sources must be available for each accumulator, each of them meeting the above requirements (point 1) to allow pump operation. - A double power source combining electric power and compressed air is recommended. - Electrical pump Conventional - Electric, Motor Driven Pumps

1. Hydraulic fluid; a suitable hydraulic fluid must be used in the accumulator (hydraulic oil or water with lubricant). Diesel, motor oil, kerosene or any other similar fluid are not recommended because they can damage the rubber seals. 2. Reservoir capacity; each accumulator must have a tank whose capacity should be at least twice the volume of the usable fluid.

- Valve connections and other parts a. three high-accuracy pressure gauges, to read the accumulator, the manifold and the annular BOP pressure; b. pressure-regulation valve to control the annular BOP pressure value; c. by-pass valve which allows, when required, to send all the accumulator pressure on the manifold; d. check valve to separate the two pumps, the bottles and the pressure regulating valve of the BOP from the manifold; e. full-opening valves on the closing line and on the annular openings; f. full-opening valve installed on the manifold and equipped with a junction to allow fast connection to another pump;

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- Pressure regulators

- Manual Operated Regulator This Manual operated TR Regulator includes an internal override and is used as a manifold regulator for operation of the ram preventers and gate valves - Remote Operated Regulator This air operated TR Regulator provides remote regulation for operation of all types of annular preventers.

- Functioning - Control Manifold On the closing valves ("4-way valves") the following must be clearly indicated: - controlled BOP or choke line - valve position (opened, neutral, closed); During drilling operations the valves must always be in the following positions: - BOP valves in the open position (not in neutral position); - choke line hydraulic valves in the closed position. The valve controlling the blind rams closure must be equipped with a cover to prevent ram unintentional closure.

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Control Manifold - DRILLER CONTROL PANEL The remote-must be installed so that every BOP and every hydraulic valve can be remotely operated. One remote-control panel must be positioned so that it is easily accessible and another one must be put at a safe distance from the rig floor (for example in the superintendent's office). The control valves remote control system can be: - pneumatic (air) - hydraulic - electrical-pneumatic - electrical-hydraulic

33.4 ACCUMULATOR OPERATIONS The pressure accumulator functioning is characterised by the following stages: a. precharge; accumulator bottles are filled with nitrogen at the estimated precharging pressure (1000 psi); b. charge. The control fluid is pumped from the tank by the pumps, pressurised and sent to the bottle charging line. The charging process ends as soon as the accumulator pressure gets to the desired value. (charging pressure 3000 psi); c. discharge; when the control valves are actuated, the pressurised control fluid stored in the bottles is sent to the working lines to set the connected mechanisms to either opening or closure. Discharging operations cause a decrease of the accumulator pressure and the pumps may be actuated if the pressure values decrease below the defined limit. d. pump control; adequate pressure automatic switches (hydro-electrical and hydro-pneumatic) allow the pump funtionning to be controlled and actuated when the accumulator pressure decreases below the minimum value or stopped when it reaches its minimum allowable value (charging pressure). e. regulation; the control fluid pressure can be adjusted by adequate valves which allow pressure to be reduced and controlled by two regulators: - the manifold pressure regulating valve controls the ram-BOP and the hydraulic valves opening/closing pressure. - the annular BOP pressure regulating valve controls the annular BOP opening/closing pressure.

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33.5 INSPECTIONS Surface BOP Control system must be inspected according to the manufacturer's recommendations and API RP 53

34.1 FUNCTION There are several pieces of equipment in addition to the primary blowout prevention equipment that are sometimes necessary to control a kick. The equipment which furnishes closure inside the drill string is called an "INSIDE BLOWOUT PREVENTER". They are installed on the top or inside the BHA with the purpose to provide a means of closing the string for well control or even to permit to repair/replace some tools.

Inside BOP

- Manufacture specifications Inside BOP are manufactured according to API 6A (and API 7 for the connections) The relevant ISO standard is the 10423 Spec.

- Installing Checkguard valve Checkguard valve is installed as needed. Remaining top side, it is not subject to constant wear as many downhole valves are. Abrasive wear on typical drill pipe float valves results in frequent replacement and can prevent closure. Only the Checkguard landing sub is installed as the drill string is run.

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When control is needed, the valve is pumped down the drill string where it latches automatically in the landing sub. - Pumping down Checkguard valve Downward flow ar\eas are maximized for high flow capacity and long life. The check valve sits in the landing sub in the replaceable landing sleeve, latching positively. The sleeve has recessed areas into which the check valve packer seals. - Close Checkguard valve Checkguard valve seals pressure up to 15,000 psi. Yet it is lightweight and easily handled. The ball closes against upward pressure. - Retrieving Checkguard valve It is wire-line retrievable. Wire line retrievable, eliminating the need to trip the drilling string. Retrieval can also be accomplished after tripping out the drill string. In this illustration, the retrieving tool unlatches the check valve and lifts it to the surface. FLOAT VALVE Float valve may be considered an INSIDE BOP. Basically a flapper or poppet type check valve that is installed in the bit sub to prevent backflow during connections. It allows circulation only in one direction. - FVR Float Valve - Float Valve - Plain Flapper and Vented Flapper

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GRAY FLOAT VALVE Always on the rig floor ready to be installed, the hold-open type has the back pressure valve pinned in an open position so that the valve can be installed when mud is flowing. The pin is removed after installation to allow closure.

Open position

Close position

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SAFETY VALVES - Kelly Cock - Rigs with TOP DRIVE - Actuator Types - Kelly Cock The kelly cock is a safety valve placed above the kelly (UPPER KELLY COCK) and below the kelly (LOWER KELLY COCK). Its basic purpose is to provide a means of closing the string should the swivel, hose, or stand-pipe leak or rupture under conditions of a threatened blowout. This arrangement permits these items to be repaired or replaced. A special wrench to operate the kelly cock is required and must be taken in a readily accessible place known to every crew member.

- Rigs with TOP DRIVE Rigs with TOP DRIVE have two valves: A manual one on bottom part (lower kelly cock) and one on the top remotely operated (upper kelly cock).

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- Actuator Types ACTUATOR Varco Type ACTUATOR Hydril Type

ACTUATOR Hydril Type

Open position

Closed position

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35. KILL & CHOKE LINES and VALVES INDEX 35.1 FUNCTION 35.2 TYPICAL ASSEMBLY 35.3 INSPECTIONS 35.4 MANUAL VALVES & REMOTE CONTROLLED VALVES 35.1 FUNCTION The high-pressure mud circuit is the surface circuit connected to the well head; it is used to circulate with the well shut and when high pressure ratings are recorded. Its main components are high-pressure lines and valves through which the mud flows in and out of the well during blowout control. The high-pressure circuit has an extremely important function and therefore all parts must be regularly checked and maintained to ensure full efficiency and functionality. The high-pressure circuit includes: - kill lines - choke lines - choke manifold - flare lines - high-pressure valves - adjustable chokes - KILL & CHOKE LINES - Choke Line function The choke line and manifold provide a means of applying back pressure on the formation while circulating out a formation fluid influx from the wellbore following an influx or kick. The choke line (which connects the BOP stack to the choke manifold) and lines down-stream of the choke should: - Be as straight as possible - Be firmly anchored to prevent excessive whip or vibration. - Have a bore of sufficient size to prevent excessive. There can be either one or two and they are inserted in the BOP stack through drilling Spools or connected to the BOP lateral flange. On the section connected to the BOP stack two valves are installed: - manual valve - remotely operated hydraulic valve

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- Kill Line function Kill lines are an integral part of the surface equipment required for drilling well control. The kill line system provides a means of pumping into the wellbore when the normal method of circulating down through the kelly or drill pipe cannot be employed. The kill line connects the drilling fluid pumps to a side outlet on the BOP stack. The location of the kill line connection to the stack depends on the particular configuration of BOPS and spools employed; the connection should be below the ram type BOP most likely to be closed. There can be either one or two and they are inserted in the BOP stack through drilling Spools or connected to the BOP lateral flange. On the section connected to the BOP stack two valves are installed: - manual valve - remotely operated hydraulic valve

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- Reverse Line Reverse Line connects the rig floor mud manifold to the choke manifold. It allows the reverse circulating with BOP closed.

- Manufacture Specifications Choke and kill lines are builted following the API specification 16 C. They can be: - Rigid steel - Flexible hose (Coflexip) - Articulated steel (chiksan) Arranging rams is important, but choke and kill flowline (wing valves) placement is equally important to fully utilize the BOP. Again, compromises are made between the most conservative position of having no flowlines below the bottom ram and a middle road position of arranging the flowline for maximum BOP usage. ENI requirements are defined by "Well control policy" and an internal specification. ENI policy requires: - Rigid steel lines for land rigs with BOP of 10.000 or 15.000 psi w.p. - Chiksan lines and quick connections are not allowed. - Drilling spool is optional; kill and choke lines can be directly connected to the lateral outlet of the BOP.

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- KILL & CHOKE VALVES Kill lines connect mud pumps to the BOP-stack side outlets and are used to pump into the well when circulation through the pipes is not possible. There can be one or two and they can be either installed on the BOP stack through the drilling spools or connected to the BOP lateral flange. On the section connected to the BOP stack two valves are installed: - manual valve - remotely operated hydraulic valve. - Kill & Choke Valves function High-pressure valves are usually gate valves and are installed on the high-pressure mud circuit to control blowouts (kill lines, choke lines and choke manifold). Because of their particular structure, these valves must be kept either completely opened or completely closed, to avoid erosion due to the mud flow. They can be either manual or remotely operated by a hydraulic actuator. - Kill manifold Kill manifold connects the kill lines coming from BOP Stack to the (kill) line from Rig floor Mud Manifold. It allows the connection of the Cement Unit for killing operations.

- Manufacture Specifications The Gate valves are manufactured according to API 6A and API 17D.

- ENI typical assembly ENI Well Control Policy 6.1 BOP STACK SYSTEMS 6.1.1 Land Rigs, Jack-Ups And Fixed Platform a) The pressure rating requirement for BOP equipment is based on the ‘maximum anticipated surface pressure’ as stated in the Drilling Procedures Manual’. Projects that require a different working pressure in the whole system shall be agreed upon by the Company and Drilling Contractor. The minimum BOP stack requirements are as follows: A 5,000psi WP stack should have at least: • Two ram type preventers (one shear ram and one pipe ram). • One 2,000psi annular type preventer. A 10,000psi stack should have at least: • Three ram type preventers (one shear ram and two pipe ram). • One 5,000psi annular type preventer. A 15,000psi stack should have at least: • Four ram type preventers (one shear ram and three pipe ram) • One 10,000psi annular type preventer. b) While drilling, all pipe ram preventers shall always be equipped with the correct sized rams to match drill pipe being used. If a tapered drill string is being used e.g. 31/2” and 5”, one set of rams will be dressed to match the smaller drill pipe size. During casing jobs or production testing, the choice of pipe rams shall be defined by the Company, depending on external diameter(s) of the casing/drilling/testing string(s) in the operation and BOP stack composition. c) At least one ram preventer, below the shear rams, shall be equipped with fixed pipe rams to fit the upper drill pipe in use. The minimum distance between shear rams and hang-off pipe rams shall be 80cm (30”). d) The use of variable bore rams (VBRs) is acceptable but they should not be used for Eni Corporate University 381

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hanging off pipe which is near to the lower end of their operating range. e) Rig site repair of BOP equipment is limited to replacing of worn or damaged parts. Under no circumstances is welding or cutting to be performed on any BOP equipment. Replacement parts should only be those supplied or recommended by the equipment manufacturer. f) Each choke and kill line BOP outlet shall be equipped with two full bore valves, the outer valve of which will be hydraulically operated (preferably fail-safe closed). g) The minimum diameter of the choke line will be 3" ID, while the kill line should have not less than a 2" ID. Articulated choke lines (Chiksan) are not acceptable unless derogation is agreed for a particular application. h) A number of various arrangements in the position of the choke and kill line outlets are used in BOP stack configurations throughout the oil industry. The rig operating manual should highlight these variations, their limitations and all the potential uses of a particular layout. i) The inclusion of shear rams requires the choke and kill lines positions to be such that the direct circulation of the kick, through the drill pipe stub after shear rams activation, can be performed with the drill string hang-off on the closed pipe rams and holding pressure. j) On a four ram BOP stack, Eni-AGIP recommends that the positioning of choke and kill line outlets below the lowest pipe rams be avoided as these are the like the last resort ‘Master Valve’ of the BOP stack.

- Standard ENI configuration of 3 rams

- Standard ENI configuration of 4 rams

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35.3 INSPECTIONS The Kill & Choke lines and valves shall be inspected (modally and frequency) according to the manufacturers recommendations and as per API RP 53. ENI requirements are defined by an internal specification that stipulates the Kill & Choke lines and valves shall be recertified by a Manufacturer authorized workshop at least every five years. Note: For the rigid lines is requested the Thickness measurements For H2S service equipment the Hardness is required

- Cameron Manual Valve FLS-R FLS-R Gate Valves were designed for use as manuals valve in high pressure, large bore applications. These valves incorporate a lower balancing stem and a unique ball screw mechanism for ease of operation in the field. The FLS-R is value-engineered for reliability, low torque, ease of operation and service. The FLS-R has many of the same features as the FLS, including the gate and seat design and the pressureenergized lip seal technology. - Features Bi-directional design. Positive metal-to-metal sealing (gate-to-seat and seattobody). Lower stem balances pressure thrust on upper stem to reduce torque, prevent body cavity pressure build-up during operation, and provide position indication. Spring-loaded, pressure energized, non-elastomeric stem seal. Pressure-energized metal-to-metal bonnet seal. Either stem can be backseated to allow stem seal replacement with valve under pressure. Grease injection fittings located on the downstream side of the stem and the balancing stem backseat for safety. FLS-R Gate Valve

- Tailrod Hydraulic Actuators Cameron Tailrod Hydraulic Actuators are used on FL and FLS Gate Valves in landbased drilling applications. - Features Cylinder wall can withstand a non-shock pressure of 3000 psi. Cylinder ports are located a sufficient distance from the cylinder head to allow piston to cover the exhaust port before the end of the stroke, providing sufficient damping to protect the valve from shock loading. Tailrod passes through a stuffing box in the valve body, compensates for the volume displaced by the operating stem, and provides visual indication of valve opening and closing. Tailrod and operating stem have backseating shoulders which allow replacement of the stem packing while valve is under pressure.

36. CHOKE MANIFOLD & MUD GAS SEPARATOR INDEX 36.1 CHOKE MANIFOLD - CHOKE MANIFOLD FUNCTION - TYPICAL CHOKE MANIFOLD ASSEMBLY - CHOKE MANIFOLD COMPONENTS - CHOKE MANIFOLD INSPECTIONS 36.2 MUD GAS SEPARATOR - MUD GAS SEPARATOR FUNCTION - TYPES OF MUD GAS SEPARATORS - MUD GAS SEPARATOR INSPECTIONS 36.1 CHOKE MANIFOLD - CHOKE MANIFOLD FUNCTION The BOP can close in the well but additional equipment is needed to allow controlled release of the well fluids, to circulate under pressure, to bleed pressure and to allow injection against high well pressure. Variable chokes control the release of well fluids under pressure, but, because of abrasive wear and possible plugging, at least two are required. Those chokes must be manifolded in order to quickly change from one to the other. - Features The choke manifold is composed of a group of valves and lines connected to the well head through the choke lines. It is used, during blowout control, to maintain the correct back pressure adjusting the flow exiting the well through an adjustable choke. The choke manifold can be equipped with a buffer chamber to convey high-pressure exit flows to a single line and to the connected discharge line (flare line, shale shaker, waste pits and mud gas separator). The buffer chamber has a lower working pressure value than all other choke manifold areas. Such difference should be kept into account during pressure tests. Flare lines are used to convey any gas coming from the choke as far from the well as possible. In case of small quantities, the gas is simply discharged, whereas in case of large volumes it is burnt. Such lines have to be as straight as possible, avoiding bendings and turns to reach the farthest possible area (towards the wind direction); they also have to be anchored to the ground to prevent them from moving because of vibrations due to violent gas flows. After being installed, they have to be field tested at a reasonably low pressure value, high enough to grant certainty of sealing. - Manufacture Specifications See Chapter "Manufacture Specification" in subject "KILL & CHOKE LINE and VALVES"

- Manual / Remote Control Adjustable Chokes Chokes are valves with an adjustable hole to control the fluid flow coming from the well. They can be either manually operated (shutter cock) or remotely hydraulically operated (automatic control). Their main function is to provide back pressure to balance the well pressure to allow blowouts to be controlled. Manual chokes are usually kept as reserve chokes, while during blowout control operations automatic chokes are preferably used since they can certainly provide greater safety and functionality (they can be remotely controlled).

- DRILLING CHOKE CONTROL PANEL
The function of the remote hydraulic choke control system is to provide reliable control of the drilling choke from one or more remote locations with the sensitivity and resolution required to perform all well control procedures which the choke valve is designed to provide, including: 1. well flow shut-in procedures. 2. throttling of mud, gas, liquid hydrocarbons and formation debris at any rate of flow up to the physical capacity of the internal flow conduit.

The control system shall provide: 1. An actuator capable of setting the orifice in the choke at any size from fully open to fully closed at any pressure up to the rated working pressure of the choke. 2. Power hydraulic fluid to the choke actuator in sufficient pressure and volume to completely close the choke from the fully open position in 30 seconds. 3. Operating controls enabling the operator to set orifice openings of any size up to fully open that will result in any annulus pressure desired (r10 psi) from O psi to the choke rated working pressure. The control device should be suitably marked for direction of control. 4. A choke position indicator that shows at the control console the relative position of the choke trim or relative orifice size as a percentage of fully open. 5. A gauge on the control panel for rig air to display the air or gas pressure available to power the console P-P. 6. A gauge on the control panel to display system hydraulic pressure, from the hydraulic pump or accumulator system. 7. Drill pipe and casing pressure gauges scaled O psi to fully rated working pressure of the choke. These gauges are clearly marked "Drill Pipe Pressure" or "Casing Pressure" and must be independent systems from other gauge systems.

36.2 MUD GAS SEPARATOR - MUD GAS SEPARATOR FUNCTION The mud gas separator is used to separate gas from drilling fluid that is gas cut. The separated gas can then be vented a safe distance from the rig.

- Manufacture Specifications Mud Gas Separator is manufactured according to API RP 53. ENI requirements are defined by an internal specification. The dimensions of a separator are critical in that they define the volume of gas and fluid a separator can effectively handle. An example of some mud gas separator sizing guidelines can be found in: SPE Paper No. 20430: Mud Gas Separator Sizing and Evaluation, G.R. MacDougall, December 199 l Mud gas separator

Mud Gas Separator per Land Rig

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- TYPES OF MUD GAS SEPARATORS Generally, two basic types of mud gas separators are in use. The most common type is the atmospheric mud gas separator, sometimes referred to as a gas buster or poor-boy separator. Another type of mud gas separator is designed such that it can be operated at moderate back pressure, usually less than 100 psi (0.69 MPa), although some designs are operated at gas vent line pressure which is atmospheric plus line friction drop. All separators with a liquid level control may be referred to as pressurized mud gas separators. - Operational Both the atmospheric and pressurized mud gas separators have advantages and disadvantages. Some guidelines are common to both types. A bypass line to the flare stack must be provided in case of malfunction or in the event the capacity of the mud gas separator is exceeded. Precautions must also be taken to prevent erosion at the point the drilling fluid and gas flow impinges on the wall of the vessel. Provisions must be made for easy clean out of the vessels and lines in the event of plugging. Unless specifically designed for such applications, use of the rig mud gas separator is not recommended for well production testing operations.

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SWACO's H2S Mud/Gas Separator Is a field proven and extremely reliable necessary piece of safety equipment for today's drilling operations. It is ideal for use where drilling is likely to encounter large volume of gas, sour gas or when an operator is drilling with an underbalance mud column. The H2S Mud/Gas Separator is primarily used to separate and safely vent large pockets of free gas than may include toxic gases such as hydrogen sulfide from the drilling mud system. SWACO's H2S Mud/Gas Separator SMEDVIG Mud Gas Separator

37. INSTRUMENTATION INDEX 37.1 FUNCTION 37.2 PARAMETERS 37.3 SENSORS AND INDICATORS 37.4 INTERFACE (Panels, Consoles) 37.5 INTEGRATED SYSTEMS 37.1 FUNCTION The function of the instrumentation on a drilling rig is to provide a continuous readout of selected parameters during normal operations. The instruments in Driller's console has the important role of protecting the personnel and the rig. - Output Data source Comes directly from sensors installed on measuring points. OR Is calculated on output data provided by sensors 37.2 PARAMETERS

37.3 SENSORS AND INDICATORS Sensors are used where it is necessary to take remote measurements. Sensor can be: - Hydraulic The Hydraulic sensor are normally used on Hook load sensor. They are installable in dangerous area. - Pneumatic In the past, Pneumatic sensors were used because they where installable in dangerous areas, but they are sensitive to the Rig working location environment and to the used compress air purity. - Electronic Those of Electronic type are even more used because they are more accuracy, easily interfaceble and compatible with acquisition system and data elaboration. Hook Load Indicator The Hook Load indicator uses a Hydraulic sensor installed on the dead line anchor, which transforms the Load to a pressure signal read by a load force gauge.

- Electronic Digital Gauge This new electronic Digital Gauge is available in different levels of functionally, from a simple single input display to a full function dual input alarmed display system with - graphical trend display, calculated values, and WITS. Designed to meet UL and CENELEC standards for intrinsic safety, the unit operates off its own battery pack or external power source. Virtually any drilling parameter display by a hydraulic or electronic analog indicator can now be displayed more accurately and reliably using the Digital Gauge.

Digital Gauge Basic Model

Digital Gauge with Optional Graphics Module

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Mud Pump Stroke Indicator

- SPM - M/D TOTCO RATEMASTER

- M/D TOTCO RATEMASTER

The M/D TOTCO RATEMASTER represents a significant advancement over traditional methods of measuring rotary table RPM and pump SPM. Since there are no generators required to create a signal, there are no moving parts. All SPM sensing is done by permanently mounted oil-tight proximity switches. The RPM sensor is a magnetically activated probe mounted next to the rotary table or adjacent to an object that rotates in proportion to the table. The microprocessor control box outputs both pulse and analog signals that can be utilized by devices such as: - Electric Meters - Drilling Recorders - Electronic Circular Recorders - Dual Digital Pump Stroke Counters - Battery Operated Pump Stroke Counters

- M/D TOTCO The M/D TOTCO solution to measuring rotary torque on electric rigs it accurate, simple, and reliable, having proven itself over the years in hundreds of installations word-wide. The M/D TOTCO ERT system display torque on a rugged panel or box mounted meter calibrated in either foot pounds or metric equivalents. - Simple, no moving parts to wear out - Split core transducer measuring electrical current to the motor clamps around power cable, no shunts or direct electrical connections required. Tong Pull Indicator - TONG TORQUE H6E-Series Models and capacities to work with all manual tongs Permanent installation models for box or console include 25' hose assembly, portable installation models with 5' hose mount indicator and cylinder directly on tong handle. Capacities to 25,000 pounds line pull with metric equivalents available.

TONG TORQUE H6E-Series

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Mud Pit Level Indicator One of the most common indicators has a float that sends a signal indicating its position on the surface of the fluid from a base starting point. The two types of indicators used most often are: - Pneumatic - Electric Newer Sensors are using Ultrasonic Source which reflected the surface level of the fluid in the mud pit. - Pneumatic - Electric

- Mud Pit Level system & Recording The level in each tank of the active system is continuously compared to a preset value. Any change in level trips an audible alarm and is also shown on the display (analog or digital) on the Driller's console.

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Tank of the Active System

Flow Indicator - Mud flow Mud flow is measured by movement of a paddle positioned in the Flow-line. Valves are very rough and are reported as a percentage of the mud flow through the stand pipe. Different sensors are used.

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Drilling Recorder - Paper Recorder This paper recorder is the most commonly used today, although more rigs are becoming equipped with a digital recorder through a dedicated server. Recorders are available in 2,4,6, and 8 pen configurations. All recorders include drill string weight, penetration weight, and other parameters of you choice.

- Parameters Fluid Pressure Provides an accurate record of fluid system pressure. Changes in pressure indicate potential washouts, kicks, plugged bits, or numerous other downhole problems. Pit Level Indicates the level of drilling fluid in the pits. A gain or loss in pit level is a warning of kicks or lost circulation. Fluid Flow Provides a relative record of fluid flow in the return line. Significant flow changes could indicate lost circulation, an influx of formation fluid, or a kick. Weight This measurement is sensitive enough to detect downhole problems such as tight hole or cave-ins at they occur. Penetration This parameter is indicated on the English chart by a short mark for each foot drilled and a longer mark for each five feet. On metric charts, indications are at 1/4 and full meters. Rotary RPM Indicates the revolutions per minute of the rotary table, an important function for optimum penetration. Torque Shows electric or hydraulic rotary torque changes during drilling which inform the driller of formation transitions, worn bit, and tight or out-of-gauge hole. Pump Rate RPM Permits accurate calculations of fluid volume pumped into the circulating system. Comparison of pump rate.

- Noise limits In Italy, noise limits on Rigs working near to home environment are defined by Ministerial Decree DPCM 1 March 1991. Since Drilling Rigs are mobile Rigs and the location of Rig site and its configuration changes from time to time, the government has established a noise level (Leq (A)) requirement. Leq (A) = Equivalent continuous Level of pondered sonorous pressure "A" - Decibel (Db) definition Decibel is used to define acoustic energy level in acoustic; it is equivalent to 10 times the decimal logarithmic of the rate between the examined value in pa and the reference value (20 pa). The chart on the right shows the relationship between acoustic pressure and Db. Acoustic pressure and Db

39. WINTERIZATION SYSTEM INDEX 39.1 GENERAL 39.2 COMPONENTS 39.3 SOME OF THE MAIN DATA

39.1 GENERAL - Extreme cold weather In order to operate continuously in extreme cold weather, Drilling Rig need to be properly equipped. - Wind Chill Effect When relevant, the WIND CHILL can have a big effect on the temperature.

39.2 COMPONENTS Equipped used to isolate the rig include: - Tarpaulin Covering - Steam Boilers and Steam Radiators - Warm Air Boilers - Electric Resistance Heating (in mud pits) - Tarpaulin Covering Many areas are covered in order to contain the heat produced by boilers and other equipment. This helps protect personnel from the cold weather and wind. It is preferable to use tarpaulins (made of fireproof materials) since they can be removed during the warmer weather. Areas usually covered are: Eni Corporate University 414

Steam, generated by diesel oil heater, is produced at variable pressure and distributed through lines to various heating points where radiators (ruffneck heaters) are installed. It is a good practice having a stand by boiler ready to work as back up.

Ruffneck heaters

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- Warm Air Boilers Hot air generated by a diesel oil / gasoline boiler is distributed by lines and electric fans at the heating point. Warm air boilers are used where steam lines can't be used. They are easy to install and do not require much maintenance. - Electrics Aeroterm Hot air generated by an electric resistance is distributed through an electric fan. They are used in remote areas of the rig such as the monkey board.

- Electric Resistance Heating (in mud pits) They are introduced into the mud pits and water pits and activated in order to avoid fluid cooling. Moreover, proper electric cables are used with resistance functions that are wrapped around the lines exposed to the weather.

40.1 GENERAL - Hydrogen Sulphide (H2S) Hydrogen Sulphide (H2S) is a toxic gas that can be present in crude oil and natural gas. Sulphur Dioxide (S02) is the effect of the combustion of H2S and is toxic as well. H2S has the following tolerance limits: Exposure at 10 ppm for 5 days per week (for a lifetime). Consequence for higher concentrations are listed below: Table: Consequence for higher concentration

- Acoustic and visual alarm Acoustic and visual alarm system is pre-set at two levels. The first level of pre alarm operates the yellow light and an intermittent sound. The second level of alarm operates the red light and a continuous sound.

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- PORTABLE MONITORING SYSTEMS - Personal air control (PAC) PAC (Personal Air Control) equip personnel working in potentially dangerous area with risk of toxic gas' presence. - Multi-Gas Detector Detection devices to monitor for toxic gas type and its quantity in PPM. Personal air control Multi-Gas Detector

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40.3 BREATHING APPARATUS PROTECTION SYSTEM - Fixed system (air cascade) - FIXED SYSTEM'S COMPONENTS - Fixed system (air cascade) When drilling a well with H2S, it is a good ENI E&P practice to install a fixed system (air cascade) to distribute pressurised air that allows personnel to breathe non-contaminate air in the event of an emergency. This system consist of: - A tank with pressurised air able to guarantee 10 hours of breathing for 10 people. - 2 compressors located in opposite positions to recharge the system and guarantee pure air input. - A distribution system in a strategic area.

- Cylinders Recharging - Charging rate of 15.5 cfm/440 lpm. - Includes a purification system to deliver breathing air to meet EN 132. - Charging pressure up to 3000 psi - Includes an automatic shut down facility on the detection of CO H2S and SO4

Electrical air compressor

High Pressure, Diesel Powered Compressor

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- DISTRIBUTION SYSTEM - Manifold and Breathing apparatus location Delivery Station Location Rig Floor Derrick man Platform Well head area Choke manifold area Mud Mixing area Mud Pump area Mud Tanks area Shale Shaker Area Well Test Area

10 minute breathing apparatus They are provided to all the personnel working on the Rig site. They are used to reach the safety points in case of emergency. The world's most popular escape set with current users as diverse as NASA in the USA, navies on every continent, and industrial customers worldwide. - All round vision, anti - misting PVC hoot - 10 minutes of self - contained breathing air for escape (400 litres at 40 litres per minute) Eni Corporate University 425

- Arktos In severe weather conditions, for survival, special Amphibious Life Boats have been created for Kazakistan operations.

- Amphibious Life Boats

- Helicopters Helicopters are the main means of transport for all Offshore installations or onshore in the bush (Nigeria Ecuador, etc).

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ESCAPE SLIPWAY - Escape Slipway - Escape line for derrickman On land rigs, for the derrickman safety from the monkey board there is an aerial ropeway to permit a fast escape without using stairs. This escape line is provided with a cinetic device for slackening of speed and stopping. - Escape Slipway - Escape line for derrickman

41.4 OMNIDIRECTIONAL FOGHORN

Like in the Navy, offshore installations must have - Omnidirectional Foghorn to be used in poor visibility conditions.

- Omnidirectional Foghorn

- Device

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41.5 PERSONNEL LIFTING DEVICE

- Man Riding Man riding is the equipment used to lift personnel. After few accident happened in the oil field, it has been decided to build a specific tool for man lifting. It can pull a max weight of 150 kg otherwise it stops itself. Man Riding Baskets

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41.6 FIRE FIGHTING SYSTEM - Equipment - Hydrants - Extinguisher

- Helideck Helideck has a dedicated fire fighting foam system with dedicated trained people ready anytime helicopter lands. The system works with sea water and foam together.

- Derrick signalling All rigs must have Day and Night Signalling consisting in red or orange lights on top of the derrick

Derrick safety device

Safety Belt

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42. COMUNICATION SYSTEMS INDEX 42.1 COMMUNICATIONS 42.2 OFFSHORE RIGS INTERCOMMUNICATION SYSTEM 42.3 LAND RIG REQUIREMENTS 42.1 COMMUNICATIONS The three most common systems of communication on offshore drilling rigs are: - Radio (with fax), - Microwave - Satellite - Radio Communication FM radio has replaced single side band as the favored radio communication. The rig, workboats and the shore base are linked by radio. - Microwave Communications Microwave communications are "line-of-sight", meaning that the signal must not be blocked by earth's curvature or any other obstruction. Signals are transmitted between dish-shaped antenna which in line pointed at each other. Microwaves can only be used if the rig is close to shore or to another fixture (such as a platform) which can re-transmit the signal. - Satellite Satellite is the most expensive means of communication. However, in remote locations, it is the only suitable system. Governmental permits are required. 42.2 OFFSHORE RIGS INTERCOMMUNICATION SYSTEM S.7. RIG INTERCOMMUNICATION SYSTEM

S.7.1 Telephone system 1 2 3 Able to Communicate between the following

HULL: Usually triangular; rarely square. LEGS: Lattice shaped, they can either the shell type or truss type. Triangular or square cross section styles are most common. CANTILEVER: Allows the derrick to be skidded to work on other wells on multi-well platforms

- Leg lenght, Jack house and Spud can Leg lenght determines the maximum depth for the jack-up. Racks are welded on each corner of the leg to all the pinion to move up and down the leg ( jack house). Legs are indipendent of each others. A spud can is installed below each leg to facilitate better penetration of the sea bed. A jetting system is installed in each leg to wash out in jack down and leg recovering.

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Drilling Rigs

- Jack Up with Spud Can or Mat Supported Depending on the sea bed, there are two main types of jack-up: With Spud Can Specifically made for soft sand and mud sea bed. Mat Supported Specifically made for hard sea bed (not used for years).

Jack Up with Spud Can

Jack Up Mat Supported

DESCRIPTION: DERRICK Some Jack-up rigs can drill multiple wells from the same location (without moving and repositionning) simply by skidding the cantilever and derrick. SLOT TYPE jack-up can drill only a single well because they cannot skid the derrick. They are not used anymore. CANTILVER TYPE jack up can position the derrick in different wells moving on orthogonal beams. All new jack-up are made in this way.

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Drilling Rigs

43.2 JACK UP TYPE All jack-ups, (Slot type or Cantilever, with spud can or mat support) are classified according to their nominal depth capacity: 150-250 ft Nominal water depth 300-350 ft Nominal water depth 400-450 ft Nominal water depth

- Geophysical survey for jack-ups The purpose of a well site geophysical survey is to investigate the sea bed or subsea to identify its litho-morphological features, determine the trend of sedimentary sequences and ascertain the presence of potential foundation hazards. Potential hazards could include: faults, shallow gas, hardband outcropping, irregular sea bed topography and manmade hazards. - Survey informations The survey must give the following informations: Water depth (bathymetric map) Morphology and consistency of the sea bed Stratigraphy and lithology of shallow gas Presence of obstacles or pre-existing structures. - Final Air Gap The final air gap is defined as the distance between the bottom of the hull of the jack up and the lowest astronomical tide. This distance is calculated to take account of prevailing weather conditions in an area, such that the rig hull is far enough out of the water to not be subjected to wave loads in the event of a heavy storm.

To achieve satisfactory rig stability on the sea bed, maximum anticipated vertical leg loads are simulated on each spudcan prior to jacking up to full operational air gap. This preloading operation is necessary to ensure that all spud cans will achieve sufficient penetration. Sufficient penetration provides a foundation stable enough to withstand the combination of maximum anticipated variable and drilling/operational loads, without further settlement or “punch through” occurring.

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Drilling Rigs

PREDICTION OF LEG PENETRATION The leg penetration study may be performed prior to the arrival of the jack-up unit at the site by using a small drilling vessel to obtain soil samples. Alternatively the study may be performed from the rig after legs have been lowered, but prior to the application of maximum load. The penetration of a footing (spudcan) into the soil occurs when the applied bearing pressure exceeds the bearing capacity of the soil. Penetration continues until the bearing capacity corresponding to ultimate soil strength equals the applied footing pressure.

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Drilling Rigs

44.4 PUNCH THROUGH

Punch through is the term used to describe a sudden breach of the seabed by one or more spudcans. Punch through would almost certainly occur only during preloading and is a rare occurrence as the site survey would normally have identified the potential for punch through. Punch through can cause extensive damage to a jack-up and emphasizes the reason to perform a full preloading with minimum air gap (usually 5-10 ft / 1.5 – 3 m).

Different formations Punch through occurs where the sea bed has a variety of different formations.

Swamp barges were built specifically to drill in shallow water, swamps or delta rivers , where a jack up or semisub cannot operate. They are designed to operate in 10 – 15 ft of water. Swamp barges are towed in position with Supply Vessels. Once on they take on sea water to sit on the sea bed.

Sunkar (Parker Drilling Co.) is a swamp barge modified to work in Caspian Sea. Swamp barges are usually employed in Nigeria (Niger River Delta), in Venezuela, and in the Caspian Sea.

47.1 SELF CONTAINED DRILLING RIGS Self-contained rigs installed on fixex platforms (jackets) and are usually equipped with all production facilities for early production. Sometimes the rigs are moved off after drilling phase is finished and sometimes they stay on site future workover. This in an 8 piles jacket rig in the Adriatic Sea. All modules are removed after drilling and completion. Future work over activities are done by dedicated workover rigs. 8-piles jacket rigs are installed on jackets dimensioned to drill as many wells as possible, depending on the jacket structure. The positioning of the derrick on a different well is obtained by moving the derrick structure on orthogonal beams with hydraulically operating jacks.

Self contained drilling rigs

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Drilling Rigs

47.2 JACKET RIG IN THE ADRIATIC SEA

This in an 8 piles jacket rig in the Adriatic Sea. All modules are removed after drilling and completion. Future work over activities are done by dedicated workover rigs.

- 8-piles jacket rigs installing 8-piles jacket rigs are installed on jackets dimensioned to drill as many wells as possible, depending on the jacket structure. The positioning of the derrick on a different well is obtained by moving the derrick structure on orthogonal beams with hydraulically operating jacks.

AHTS vessels are equipped with winches capable of towing drilling rigs and lifting and positioning their anchors and other marine equipment. They range in size and capacity and are usually characterized in terms of horsepower and towing capacity. AHTS vessels typically require 8,000 horsepower or more to position and service semi-submersible rigs drilling in deep water areas.

- PRODUCTION SUPPLY (PSV)

PSVs serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other vessels by cargo flexibility and capacity. In addition to deck cargo, such as pipe or drummed materials on pallets, supply vessels transport liquid mud, potable and drill water, diesel fuel and dry bulk cement. Other characteristics, such as maneuverability, fuel efficiency or firefighting capability may also be important. Towing supply vessels perform the same functions as supply vessels but are equipped with more powerful engines and a deck mounted winch, giving them the added capability to perform general towing duties, buoy setting and limited anchor handling work. Towing supply vessels are used primarily in international operations to tow, position and support jack-up drilling units.

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Drilling Rigs

- CREWBOAT / FAST SUPPLY (FSV)

Crewboats transport personnel and cargo to and from production platforms and rigs. Older crewboats are generally designed for speed to transport personnel. Newer crewboats (also referred to as fast supply vessels "FSV"), are generally larger, have greater cargo carrying capacities and are used primarily to transport cargo on a time sensitive basis.
- OIL SPILL RECOVERY (OSRV)

OSRVs specialize in providing cost-effective solutions to meet the environmental regulations of the U.S. and international energy and maritime industries. They are also used for temporary storage of recovered oil and removal of oil & hazardous waste.
- UTILITY

Utility vessels provide service to offshore production facilities and also support offshore maintenance and construction work. Their capabilities include the transportation of fuel, water, deck cargo and personnel. They can have enhanced features such as firefighting and pollution response capabilities.

- MINI-SUPPLY Mini-supply vessels vary from 145 ft. to 170 ft. in length and have enhanced cargo capacity and maneuverability as compared to standard utility vessels. Besides fuel, water and deck cargo, some minisupply vessels can transport methanol and have enhanced station keeping with dynamic positioning systems.